Illinois Power Generating 10-K 2013 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(X)	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2013.
	OR
(   )	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from           to        .

COMMISSION FILE NUMBER 333-56594

ILLINOIS POWER GENERATING COMPANY

(Exact name of registrant as specified in its charter)

Illinois	37-1395586
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

601 Travis, Suite 1400, Houston, Texas 77002

(Address of principal executive offices and Zip Code)

Registrant’s telephone number, including area code: (713) 507-6400

Securities Registered Pursuant to Section 12(b) of the Act: None.

Securities Registered Pursuant to Section 12(g) of the Act: None.

Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ( ) No (X)

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes (X) No ( )

Indicate by checkmark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ( ) No (X)

As indicated above, the registrant is not required to file reports under the Securities Exchange Act of 1934. However, the registrant has filed all Exchange Act reports for the preceding 12 months.

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes (X) No ( )

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

(X)

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company
( )	( )	(X)	( )

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes ( ) No (X)

As of June 30, 2013, all 2,000 shares of the registrant’s common stock were held by its former parent, Ameren Energy Resources Company, LLC, a subsidiary of Ameren Corporation.

As of March 21, 2014, there were 2,000 outstanding shares of common stock, without par value, of the registrant, all of which were held by its parent, Illinois Power Resources, LLC, an indirect wholly-owned subsidiary of Dynegy Inc.

OMISSION OF CERTAIN INFORMATION

The registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS AND ABBREVIATIONS		1
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	13
Item 2.	Properties	13
Item 3.	Legal Proceedings	13
Item 4.	Mine Safety Disclosures	13
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14
Item 6.	Selected Financial Data	14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 8.	Consolidated Financial Statements and Supplementary Data	27
	Selected Quarterly Information	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	66
Item 9A.	Controls and Procedures	66
Item 9B.	Other Information	66
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	67
Item 11.	Executive Compensation	67
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	67
Item 13.	Certain Relationships and Related Transactions, and Director Independence	67
Item 14.	Principal Accounting Fees and Services	67
PART IV
Item 15.	Exhibits and Financial Statement Schedules	68
SIGNATURES		69
EXHIBIT INDEX		70

GLOSSARY OF TERMS AND ABBREVIATIONS

Unless the context indicates otherwise, throughout this report, the terms “Genco,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Illinois Power Generating Company and its direct and indirect subsidiaries. When appropriate, subsidiaries of Genco are named specifically as we discuss their various business activities.

2010 Genco Credit Agreement - Ameren and Genco’s $500 million multiyear senior unsecured credit agreement, which was terminated on November 14, 2012.

AER - Ameren Energy Resources Company, LLC, an Ameren subsidiary and predecessor to New AERG.

AERAcquisition - December 2, 2013 acquisition of New AER and its subsidiaries by IPH, including EEI and Genco.

AERG - AmerenEnergy Resources Generating Company, a former Ameren subsidiary.

Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition and disposition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, and is our former parent.

Ameren Illinois - Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois, doing business as Ameren Illinois.

Ameren Missouri - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri, doing business as Ameren Missouri.

Ameren Services - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

ARO - Asset retirement obligation.

ASU - Accounting Standards Update.

Btu - British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

CAA - Clean Air Act.

CAIR - Clean Air Interstate Rule.

Capacity factor - A percentage measure that indicates how much capacity was used during a specific period.

CCR - Coal combustion residuals.

CIPS - Central Illinois Public Service Company, an Ameren Corporation subsidiary, renamed Ameren Illinois Company on October 1, 2010, that operates a rate-regulated electric and natural gas transmission and distribution business, all in Illinois.

CO₂ - Carbon dioxide.

CSAPR - Cross-State Air Pollution Rule.

CRCG - Commodity Risk Control Group.

CT - Combustion turbine electric facility used primarily for peaking capacity.

DOE - Department of Energy.

Dynegy - Dynegy Inc., a Delaware Corporation and indirect parent of Genco, effective December 2, 2013.

EEI - Electric Energy, Inc., an 80%-owned Genco subsidiary that operates merchant electric generation facilities in Illinois and FERC-regulated transmission facilities in Illinois and Kentucky. The remaining 20% ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.

EPA - Environmental Protection Agency, a United States government agency.

Equivalent availability factor - A measure that indicates the percentage of time a facility was available for service during a period.

ERISA - Employee Retirement Income Security Act of 1974, as amended.

Exchange Act - Securities Exchange Act of 1934, as amended.

FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

FERC - Federal Energy Regulatory Commission, a United States government agency.

FCC - Federal Communications Commission, a United States government agency.

GAAP - Generally accepted accounting principles in the United States of America.

Genco - Illinois Power Generating Company (formerly known as Ameren Energy Generating Company), an IPR subsidiary that operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI.

Gigawatthour -One thousand megawatthours.

GHG - Greenhouse gases, primarily carbon dioxide, and including methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons and perfluorocarbons.

IBEW - International Brotherhood of Electrical Workers, a labor union.

ICC - Illinois Commerce Commission, a state agency that regulates Illinois utility businesses.

IFS - Illinois Power Fuels and Services Company (formerly known as Ameren Fuels and Services Company), an IPH subsidiary.

IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.

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IPCB - Illinois Pollution Control Board.

IPH - Illinois Power Holdings, LLC, an indirect wholly-owned subsidiary of Dynegy Inc.

IPM - Illinois Power Marketing Company (formerly known as Ameren Energy Marketing Company), an IPH subsidiary that markets power generated by Genco, IPRG and EEI.

IPR - Illinois Power Resources, LLC, an IPH subsidiary and parent of Genco, formerly known as New AmerenEnergy Resources, LLC.

IPRG - Illinois Power Resources Generating LLC, an IPH subsidiary, formerly known as New AERG, LLC and successor to Ameren Energy Resources Generating Company, which operates a merchant electric generation business in Illinois.

IRC - Internal Revenue Code.

IUOE - International Union of Operating Engineers, a labor union.

Kilowatthour - A measure of electricity consumption equivalent to the use of 1,000 watts of power over one hour.

MATS - Mercury and Air Toxics Standards.

Medina Valley - AmerenEnergy Medina Valley Cogen, LLC, an AER subsidiary, which owned a 40-megawatt natural gas-fired electric facility. This facility was sold in February 2012.

Megawatthour or MWh - One thousand kilowatthours.

MISO - Midcontinent Independent System Operator, Inc., an RTO.

Mmbtu - One million Btus.

Money pool - Borrowing agreement among Ameren’s non-state regulated businesses to coordinate and provide for certain short-term cash and working capital requirements. This agreement was terminated in connection with the AER Acquisition.

Moody’s - Moody’s Investors Service Inc., a credit rating agency.

MPS - Multi-Pollutant Standard, a compliance alternative within Illinois law covering reductions in emissions of SO₂,NO_xand mercury, which Genco and EEI elected in 2006.

MTM - Mark-to-market.

NAAQS - National Ambient Air Quality Standards.

NERC - North American Electric Reliability Corporation.

New AER - New Ameren Energy Resources, LLC, a limited liability company formed as a direct wholly owned subsidiary of AER. Prior to the sale of New AER to IPH, AER transferred to New AER all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren, and (iii) the assets and the environmental and closure liabilities associated with Genco’s closed Meredosia and Hutsonville facilities.

NO₂ - Nitrogen dioxide.

NO_x - Nitrogen oxide.

NOL - Net operating loss.

NPNS - Normal purchases and normal sales.

NSPS - New Source Performance Standards, a provision under the CAA.

NSR - New Source Review provisions of the CAA which include Nonattainment New Source Review and PSD regulations.

NYMEX - New York Mercantile Exchange.

OCI - Other comprehensive income (loss) as defined by GAAP.

OTC - Over-the-counter.

PJM - PJM Interconnection LLC, an RTO.

PRB - Powder River Basin.

PSA - Power supply agreement.

PSD - Prevention of Significant Deterioration, a provision under the CAA.

PUHCA 2005 - The Public Utility Holding Company Act of 2005.

RTO - Regional Transmission Organization.

S&P - Standard & Poor’s Ratings Services, a credit rating agency.

SEC - Securities and Exchange Commission, a United States government agency.

SERC - SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.

SO₂ - Sulfur dioxide.

Transaction Agreement - The March 14, 2013 agreement between Ameren and IPH to divest New AER to IPH.

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PART I

ITEM 1.    BUSINESS

GENERAL

We are an electric generation subsidiary of IPR, which is an indirect wholly-owned subsidiary of Dynegy. We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. We have an 80% ownership interest in EEI, which we consolidate for financial reporting purposes. EEI operates merchant electric generation facilities in Illinois and FERC-regulated transmission facilities in Illinois and Kentucky. We also consolidate our wholly-owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.

Our revenues are determined by market conditions and contractual arrangements. As discussed below, we sell all of our power and capacity to IPM through PSAs. IPM attempts to optimize the value of our available generation capacity and energy and to mitigate risks through a variety of techniques, including wholesale sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, spot market sales in MISO, participation in structured capacity market auctions and bilateral sales in MISO and PJM and financial hedging transactions, including options and other derivatives. Please read Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7, Note 2—Related Party Transactions and Note 8—Derivative Financial Instruments for further discussion.

On December 2, 2013, we were acquired by IPH, an indirect wholly owned subsidiary of Dynegy. In connection with the AER Acquisition, Ameren retained certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. We did not apply “push-down accounting” as a result of the AER Acquisition which would require the adjustment of assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. Our approximately $825 million in aggregate principal amount of long-term notes payable remain outstanding as an obligation of Genco. IPH and its direct and indirect subsidiaries, including Genco, are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries, for the purpose of minimizing risk of claims against Dynegy for IPH’s and our obligations. Further, IPH and its direct and indirect subsidiaries present themselves to the public as separate entities.

On March 28, 2012, we entered into a put option agreement with AERG, which gave us the option to sell to AERG the Elgin, Gibson City and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”). Our original Put Option agreement with AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley (the “Put Option”). On March 14, 2013, Ameren entered into a Transaction Agreement, which was completed on December 2, 2013 (the “Acquisition Date”). Immediately prior to Ameren’s entry into the Transaction Agreement with IPH on March 14, 2013, we exercised our option under the Put Option agreement with Medina Valley and received an initial payment of $100 million for the then pending sale of the Gas-Fired Facilities to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and our sale of the Gas-Fired Facilities to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these Gas-Fired Facilities to Medina Valley and received additional after-tax cash proceeds of approximately $38 million. Medina Valley entered into an agreement to sell the Gas-Fired Facilities to Rockland Capital (the “Rockland Agreement”). The sale of the Gas-Fired Facilities to an affiliate of Rockland Capital closed on January 31, 2014. Under the Put Option, Medina Valley is obligated to pay us after-tax proceeds realized on the sale of the Gas-Fired Facilities in excess of $138 million, net of any indemnifications per the Rockland Agreement, within two years of January 31, 2014.

For additional information about the development of our business, our business operations and factors affecting our operations and financial position, please read Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7 and Note 1—Summary of Significant Accounting Policies for further discussion.

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Our Power Generating Facilities

The following table shows what the capability of our facilities is anticipated to be at the time of our expected 2014 peak winter electrical demand:

Primary Fuel Source	Facility	Location	Net Megawatt Capability (a)
Coal	Newton	Newton, Ill.	1,225
	Joppa (EEI)(b)	Joppa, Ill.	802
	Coffeen	Coffeen, Ill.	915
Total			2,942

__________________________________________

(a) Net megawatt capability is the generating capacity available for dispatch from the facility into the electric transmission grid.

(b) Genco owns an 80% interest in EEI. Total capacity of this facility is 1,002 megawatts. Additionally, Joppa has 235 megawatts of natural gas-fired capacity which is currently not operating and therefore excluded from the table above.

RATES AND REGULATIONS

General Regulatory Matters

We must receive FERC approval to enter into various transactions, including certain acquisitions, mergers, consolidations and divestitures involving assets subject to FERC jurisdiction.

We are also subject to mandatory reliability standards, including cybersecurity standards, adopted by FERC to ensure the reliability of the bulk power electric system. These standards are developed and enforced by NERC pursuant to authority given to it by the FERC. If we or any of our subsidiaries were found not to be in compliance with any of these mandatory reliability standards, we could incur substantial monetary penalties and other sanctions.

Environmental Matters

Certain of our operations are subject to federal, state and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These environmental statutes and regulations include requirements for identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting and emergency response in connection with hazardous and toxic materials; safety and health standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants, the protection of natural and cultural resources and the management of waste and byproduct materials. Failure to comply with those statutes or regulations could have material adverse effects on us. For such failure, we could be subject to criminal or civil penalties by regulatory agencies or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.

In addition to existing laws and regulations, the EPA is developing environmental regulations that would have a significant impact on electricity generators. These regulations could be particularly burdensome for certain companies, including ours, that operate coal-fired facilities. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of GHG emissions from new facilities; revised NAAQS for SO₂, NO_x and fine particulates; the CSAPR, which would have required further reductions of SO₂ and NO_x emissions from facilities; a regulation that governs management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, metals, and acid gases from facilities; revised NSPS for particulate matter, SO₂ and NO_x emissions from new sources; new standards for cooling water intake structures at facilities, and new effluent standards applicable to discharges from steam-electric generating units. The EPA is expected to propose CO₂ limits for existing fossil fuel-fired electric generation units in 2014. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our facilities, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures. The

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decision to make pollution control equipment investments depends on whether the expected future market price for power reflects the increased cost for environmental compliance.

For additional discussion of environmental matters, including NO_x, SO₂ and mercury emission reduction requirements, and a discussion of the EPA’s Notice of Violation alleging violations of Clean Air Act permitting requirements at our Newton facility, please read Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Note 10—Commitments and Contingencies.

TRANSMISSION AND SUPPLY OF ELECTRIC POWER

EEI operates its own balancing authority area and its own transmission facilities in southern Illinois and northern Kentucky. The EEI transmission system is directly connected to the transmission systems of MISO, the Tennessee Valley Authority and Louisville Gas and Electric Company. EEI’s facilities are dispatched separately from those of Genco.

Genco and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa and Texas. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by NERC and its regional entities, such as SERC, which are enforced by FERC. Genco and EEI must comply with these standards, which are in place to ensure the reliability of the bulk electric power system.

Power Supply Agreements

Genco, exclusive of EEI, has a PSA with IPM, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPRG has entered into a similar PSA with IPM. Under these PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice. On February 26, 2014, Genco also entered into a collateral agreement with IPM pursuant to which Genco provides collateral to IPM to secure obligations of IPM applicable to Genco’s assets.

EEI also has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that IPM pays for capacity is set annually based upon prevailing market prices. IPM pays spot market prices for the associated energy. In addition, EEI may at times purchase energy from IPM to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016. Please read Note 2—Related Party Transactions for further discussion on the power supply agreements.

POWER GENERATION

The following table presents the fuel source of our electric generation, excluding purchased power, for the years ended December 31, 2013, 2012 and 2011:

	Coal	Natural Gas	Oil
2013	97%	3%	(a)
2012	92%	8%	(a)
2011	99%	1%	(a)

__________________________________________

(a) Less than 1% of total fuel supply.

The following table presents the cost of fuels for our electric generation for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(Dollars per Mmbtu)	2013		2012		2011
Coal (a)	$	2.276	$	2.324	$	2.230
Natural gas (b)	$	4.916	$	3.380	$	7.272
Weighted average – all fuels (c)	$	2.337	$	2.413	$	2.322

_________________________________________

(a) The fuel cost for coal represents the cost of coal, the costs for transportation, which include railroad diesel fuel additives, and the cost of emission allowances.

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(b) The fuel cost for natural gas represents the cost of natural gas and firm and variable costs for transportation, storage, balancing and fuel losses for delivery to the facility. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the facilities.

(c) Represents all costs for fuels used in our facilities, to the extent applicable, including coal, natural gas and handling.

Coal

We have long-term agreements in place to purchase a portion of the coal we need and to transport it to our facilities. We expect to enter into additional contracts to purchase coal from time to time. We procure coal based on our expected coal requirement needs. Our facilities burned 11.2 million tons of coal in 2013. Please read Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk for further discussion about our coal supply contracts.

During 2013, a majority of our coal was purchased from the PRB in Wyoming. From time to time we may purchase coal from the Illinois Basin. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, extreme weather and derailments. As of December 31, 2013, coal inventories were at or above targeted levels. Disruptions in coal deliveries could cause us to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

INDUSTRY ISSUES

We face issues common to the merchant electric generation industry. These issues include:

• continually developing and complex environmental laws, regulations and issues, including air and water quality standards, mercury emissions standards, and likely GHG limitations and CCR management requirements;

• the potential for changes in laws, regulations, and policies at the state and federal level;

• access to, and uncertainty in, the capital and credit markets;

• cybersecurity risk, including loss of operational control of facilities and/or loss of data, and compliance with related industry regulations;

• the potential for more competition in generation, supply and distribution, including new technologies;

• energy efficiency initiatives including reduced demand;

• the potential for re-regulation in some states, which could cause electric distribution companies to build or acquire facilities and to purchase less power from electric generation companies such as Genco;

• changes in the structure of the industry as a result of changes in federal and state laws;

• increases, decreases, and volatility in power prices due to the balance of supply and demand and marginal fuel costs;

• weakened financial strength of merchant generators, especially those with coal-fired facilities, including their ability to generate positive cash flows in competitive markets as they seek to comply with environmental regulations;

• the availability of fuel and increases or decreases in fuel prices;

• the availability of qualified labor and material, and rising costs;

• legislation or proposals for programs to encourage or mandate energy efficiency and renewable sources of power; and

• consolidation of merchant generation companies.

We are continuously monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position or liquidity. Please read Risk Factors, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7, and Note 10—Commitments and Contingencies for further discussion.

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OPERATING STATISTICS

The following table presents our key operating statistics for the past three years:

	Year Ended December 31,
(amounts in millions, except price data)	2013		2012		2011
Electric Sales – megawatthours:
Nonaffiliate energy sales (a)	—		—		1.3
Affiliate energy sales	19.0		18.4		21.9
Total	19.0		18.4		23.2
Electric Operating Revenues:
Nonaffiliate energy sales	$	89	$	1	$	57
Affiliate energy sales	709		804		1,006
Other	6		3		3
Total	$	804	$	808	$	1,066
Electric Generation – megawatthours	19.0		18.5		22.0
Price per ton of delivered coal (average)	$	39.83	$	40.77	$	39.22

__________________________________________

(a) Less than 1 million megawatthours in 2013 and 2012.

EMPLOYEES

As of December 31, 2013, we had 421 employees. As of January 1, 2014, the IBEW and the IUOE collectively represented approximately 70% of total employees. The collective bargaining agreements have four-year terms and expire in June 2015.

AVAILABLE INFORMATION

We file annual, quarterly and current reports, and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov. No information from such website is incorporated by reference herein. Our SEC filings are also available free of charge on Dynegy’s website at www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of Dynegy’s website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

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ITEM 1A.    RISK FACTORS

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

• the effects of, or changes to, MISO power procurement process;

• changes in laws and other governmental actions, including monetary, fiscal, and tax policies;

• changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers;

• the effects on demand for our services resulting from technological advances, including advances in energy efficiency and distributed generation sources, which generate electricity at the site of consumption;

• increasing capital expenditure and operating expense requirements and our ability to recover these costs in deregulated power markets;

• the cost and availability of fuel such as coal used to produce electricity;

• the effectiveness of our risk management strategies;

• the level and volatility of future prices for power, including capacity, in the Midwest, which may have a significant effect on our financial condition;

• the development of a multiyear capacity and power market within MISO;

• business and economic conditions, including their impact on interest rates, and demand for our products;

• our access to necessary capital, including short-term credit and liquidity;

• our assessment of our liquidity, including liquidity concerns which have resulted in limited access to third-party financing sources;

• the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance;

• actions of credit rating agencies and the effects of such actions;

• the impact of weather conditions and other natural phenomena on us and our customers, including the impacts of droughts, which may cause lower river levels and could limit our facilities’ ability to generate power;

• the impact of system outages;

• the effects of strategic initiatives, including mergers, acquisitions (such as the AER Acquisition) and divestitures;

• impairments of long-lived assets;

• the impact of current environmental regulations on power generating companies and new, more stringent or changing requirements, including those related to GHG, other emissions or discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of our facilities, increase our costs, result in an impairment of our assets, reduce our customers’ demand for electricity or otherwise have a negative financial effect;

• labor disputes, workforce reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;

• the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit agreements, and financial instruments;

• the cost and availability of transmission capacity for the energy generated by our facilities;

• legal and administrative proceedings; and

• acts of sabotage, war, terrorism, cybersecurity attacks or intentionally disruptive acts.

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

Investors should review carefully the following material risk factors and the other information contained in this report. The risks that we face are not limited to those in this section. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect our results of operations, financial position and

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liquidity. Please read Forward-Looking Statements above and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion.

FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks Related to the Operation of Our Business

We may not have access to sufficient capital in the amounts and at the times needed.

Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. During the first quarter 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level through at least 2016. As a result, our ability to borrow additional funds from external, third-party sources is restricted. The inability to raise debt or equity capital on favorable terms, or at all, could negatively affect our ability to maintain and to expand our business. Any adverse change in our credit ratings may further reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and natural gas supplies, among other things, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Competition in wholesale power markets, together with the age of certain of our generation facilities and an oversupply of power generation capacity in certain regional markets, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation could increase competition from these types of facilities. In addition, a buildup of new electric generation facilities in recent years has resulted in an oversupply of power generation capacity in certain regional markets we serve.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources in these areas. In addition, certain of our current facilities are relatively old. Newer plants owned by competitors will often be more efficient than some of our plants, which may put these plants at a competitive disadvantage. Over time, some of our plants may become unable to compete because of the construction of new plants, and such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions, or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities. Taken as a whole, the potential disadvantages of our aging fleet could result in lower run-times or even asset retirement.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the United States are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry.

In addition, many companies in the regulated utility industry, with which the wholesale power industry is closely linked, are also restructuring or reviewing their strategies. Several of those companies have discontinued or are discontinuing their unregulated activities and seeking to divest or spin-off their unregulated subsidiaries. Some of those companies have had, or are attempting to have, their regulated subsidiaries acquire assets out of their or other companies’ unregulated subsidiaries. This may lead to increased competition between the regulated utilities and the unregulated power producers within certain markets. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies.

Profitable operation of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates.  We manage our price exposure by entering into term contracts for PRB coal, which we use for our facilities. Our coal transportation

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requirements for our facilities are fully contracted and priced for the next several years. Transportation of PRB coal can also be affected by extreme weather, rail maintenance and accidents, slowing or stopping the delivery from the mine to the facility.

We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. Further, any changes in the costs of coal or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.

The concentration of our business in Illinois and MISO may increase the effects of adverse trends in that market, and any disruption of production at our facilities could have a material adverse effect on our financial condition, results of operations and cash flows.

A substantial portion of our business is located in Illinois and MISO. More than 70% of our plant capacity is in MISO. Further, natural disasters in Illinois, including earthquakes along the New Madrid fault line, and changes in economic conditions in MISO, including changing demographics, congestion, or oversupply of or reduced demand for power, could have a material adverse effect on our financial condition, results of operations and cash flows.

With the exception of EEI, we do not own or control transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, these transmission facilities are operated by MISO, which is subject to changes in structure and operation and imposes various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.

Other than for EEI, which owns and controls transmission lines interconnecting the EEI control area to MISO, Tennessee Valley Authority and Louisville Gas and Electric Company, we do not own or control the transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. MISO provides transmission services, administers transparent and competitive power markets and maintains system reliability. MISO operates in the real-time and day-ahead markets in which we sell energy. MISO imposes, and in the future may continue to impose, offer caps and other mechanisms to guard against the potential exercise of market power as well as price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the operation of MISO, or changes in geographic scope, rules or market operations of MISO, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. Additionally, if the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, the rates for transmission capacity from these facilities are set by others and thus are subject to change, some of which could be significant. As a result, our financial condition, results of operations and cash flows may be materially adversely affected.

Operation of power generation facilities involves significant risks customary to the power industry that could have a material adverse effect on our financial condition, results of operations and cash flows.

The ongoing operation of our facilities involves risks customary to the power industry that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport our product to customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of our business. Further, some of our facilities require periodic upgrading and improvement due to their age. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. If we are unsuccessful in operating our facilities efficiently, such inefficiency could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our energy risk management strategies may not be effective in managing fuel and electricity procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.

We are exposed to changes in market prices for natural gas, fuel, power, emission allowances and transmission congestion. Prices for natural gas, fuel, power and emission allowances may fluctuate substantially over relatively short periods of time, and at other times exhibit sustained increases or decreases, and expose us to commodity price risk. We use short-term and long-term purchase and sales contracts to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk or that they will not result in net liabilities because of future volatility in these markets.

Our business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating our facilities or our ability to operate our facilities, or increase competition, any of which would negatively impact our results of operations.

We are subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities in each of the jurisdictions in which we have operations. We incur expenses, capital and operating expenditures associated with monitoring and complying with these ever-changing laws and regulations. Potential changes in laws and regulations that could have a material impact on our business include: the introduction, or reintroduction, of rate caps or pricing constraints; increased credit standards, collateral costs or margin requirements, as well as reduced market liquidity, as a result of potential OTC market regulation; or a variation of these. Furthermore, these and other market-based rules and regulations are subject to change at any time, and we cannot predict what changes may occur in the future or how such changes might affect any facet of our business.

The costs and burdens associated with complying with the increased number of regulations, including legal representation, may have a material adverse effect on us if we fail to comply with the laws and regulations governing our business or if we fail to maintain or obtain advantageous regulatory authorizations and exemptions. Moreover, increased competition within the sector resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of our power generation earnings and cash flows generally.

Our costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect our financial condition, results of operations and cash flows.

Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of hazardous substances and waste; spills, releases and emissions of various substances (including GHGs) into the environment, and environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to us or our facilities, and litigation or enforcement proceedings could be commenced against us. Proposals being considered by federal and state authorities (including proposals regarding regulation of CCR, ash ponds, cooling water intake structures and GHGs) could, if and when adopted or enacted, require us to make substantial capital and operating expenditures or consider retiring certain of our facilities. If any of these events occur, our financial condition, results of operations and cash flows could be materially adversely affected.

Many environmental laws require approvals or permits from governmental authorities before construction, modification or operation of a power generation facility may commence. Certain environmental permits must be renewed periodically in order for us to continue operating our facilities. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. We are required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when we modify and operate our facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain any required approval or permit, or if we are unable to comply with the terms of such approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs and/or legal challenges. Further, changed interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance. As a result, our financial condition, results of operations and cash flows could be materially adversely affected. With the continuing trend toward stricter environmental standards and more extensive regulatory and permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may significantly increase in the future.

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Availability and cost of emission allowances could materially impact our costs of operations.

We are required to maintain, either through allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws, and the trend toward more stringent regulations (including regulations regarding GHG emissions) will likely require us to obtain new or additional emission allowances. If our operational needs require more than our allocated quantity of emission allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as an operating expense. If such allowances are available for purchase, but only at significantly higher prices, their purchase could materially increase our costs of operations in the affected markets and materially adversely affect our financial condition, results of operations and cash flows.

The construction of, and capital improvements to, our facilities involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled and the inability to earn a reasonable return on invested capital, any of which could result in higher costs and the closure of facilities.

We expect to incur significant capital expenditures on our facilities. These expenses include construction expenditures, capitalized interest and capital expenditures for compliance with existing and known environmental regulations. The recoverability of amounts expended will depend upon market prices for capacity and energy. Our ability to complete construction projects successfully, and within projected estimates, is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, or other events beyond our control that could occur may materially affect the schedule, cost and performance of these projects. With respect to capital expenditures for pollution control equipment, there is a risk that facilities will not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such pollution control equipment not be installed on time or perform as expected, we could be subject to additional costs and to the loss of our investment in the project or facility. All of these risks may adversely affect our financial condition, results of operations and cash flows.

We could recognize long-lived asset impairment charges related to our facilities.

We recorded a pretax charge to earnings of $199 million for the year ended December 31, 2013, to reflect the impairment of the Gas-Fired Facilities. The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower gas-fired facilities as the Elgin facility was previously impaired ($70 million pre-tax charge to earnings) under held and used accounting guidance during the fourth quarter 2012. If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period of time from a prolonged economic downturn or from advances or changes in technologies, we could experience future impairments of our power plant assets as a result. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not have a material adverse impact on our financial condition, results of operations and cash flows. As of December 31, 2013, the carrying value of long-lived assets exceeded their realizable fair value by an amount in excess of $1 billion.

Our counterparties may not meet their obligations to us and IPH affiliates may not meet their obligations to each other.

We are exposed to the risk that counterparties to various arrangements who owe us money, energy, coal or other commodities or services will not be able or willing to perform their obligations. Should the counterparties to commodity arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices.

We have obligations to other IPH companies and other IPH companies have obligations to us, as a result of transactions involving energy, coal, other commodities and services and as a result of hedging transactions. If one of these other IPH companies fails to perform under any of these arrangements, we might incur losses. Our financial condition, results of operations and cash flows could be adversely affected, resulting in our inability to meet our obligations, including to unrelated third parties.

Increasing costs associated with our participation in defined benefit retirement and postretirement plans, health care plans and other employee benefits could adversely affect our results of operations, financial position and liquidity.

Through our involvement in the Dynegy and EEI plans, our employees participate in defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. In addition to our costs under the Dynegy and EEI pension plans, the costs of providing health care benefits to our employees and retirees have

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increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with defined benefit retirement plans, health care plans and other employee benefits could increase our financing needs and otherwise materially adversely affect our results of operations, financial position and liquidity.

Our financial condition, results of operations and cash flows would be adversely impacted by strikes or work stoppages by our unionized employees.

A majority of the employees at our facilities are subject to collective bargaining agreements with various unions. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

Terrorist attacks and/or cyber-attacks may result in our inability to operate and fulfill our obligations, and could result in material repair costs.

As a power generator, we face heightened risk of terrorism, including cyber terrorism, either by a direct act against one or more of our generating facilities or an act against the transmission and distribution infrastructure that is used to transport our power.  We rely on information technology networks and systems to operate our generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information related to our employees, vendors and counterparties.

Systemic damage to one or more of our generating facilities and/or to the transmission and distribution infrastructure could result in our inability to operate in one or all of the markets we serve for an extended period of time. If our generating facilities are shut down, we would be unable to respond to MISO or fulfill our obligations under various energy and/or capacity arrangements, resulting in lost revenues and potential fines, penalties and other liabilities. Pervasive cyber-attacks across our industry could affect the ability of MISO to function in some areas. The cost to restore our generating facilities after such an occurrence could be material.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 2.    PROPERTIES

For information on our principal properties, please read “Our Power Generating Facilities” table in Business, Part I, Item 1, which is incorporated herein by reference.

EEI owns 42 miles of transmission lines as of December 31, 2013.

With only a few exceptions, we have fee title to all principal facilities and other units of property material to the operation of our business, and to the real property on which such facilities are located (subject to certain permitted liens and judgment liens).

ITEM 3.    LEGAL PROCEEDINGS

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. Material legal and administrative proceedings are discussed in Note 10—Commitments and Contingencies and incorporated herein by reference.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established trading market for our common stock. As of March 21, 2014, all outstanding shares of the registrant were held by our parent, IPR, an indirect wholly-owned subsidiary of Dynegy Inc.

ITEM 6.    SELECTED FINANCIAL DATA

	For the Years Ended December 31,
(in millions)	2013			2012			2011		2010			2009
Operating revenues	$	804		$	808		$	1,066	$	1,126		$	1,148
Operating income (loss) (a)	$	(213	)	$	(17	)	$	139	$	62		$	324
Net income (loss) attributable to Illinois Power Generating Company	$	(188	)	$	(33	)	$	44	$	(39	)	$	160
Dividends to parent	$	—		$	—		$	—	$	—		$	43
As of December 31:
Total assets	$	2,264		$	2,532		$	2,572	$	2,607		$	2,920
Long-term debt, excluding current maturities	$	824		$	824		$	824	$	824		$	823
Subordinated intercompany notes (current)	$	—		$	—		$	—	$	—		$	176
Total Illinois Power Generating Company stockholder’s equity	$	756		$	1,020		$	1,018	$	998		$	1,004

__________________________________________

(a) Includes “Impairment and other charges” of $199 million, $70 million and $35 million recorded during the years ended December 31, 2013, 2012 and 2011, respectively. Please read Note 11—Impairment and Other Charges for further discussion.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. We have an 80% ownership interest in EEI that AER transferred to us in 2010, at net book value. We consolidate EEI for financial reporting purposes. EEI operates merchant electric generation facilities in Illinois and FERC-regulated transmission facilities in Illinois and Kentucky.

On December 2, 2013, we were acquired by IPH, an indirect wholly owned subsidiary of Dynegy. In connection with the AER Acquisition, Ameren retained certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. We did not apply “push-down accounting” as a result of the AER Acquisition which would require the adjustment of assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. Our approximately $825 million in aggregate principal amount of long-term notes payable remain outstanding as an obligation of Genco. IPH and its direct and indirect subsidiaries, including Genco, are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries, for the purpose of minimizing risk of claims against Dynegy for IPH’s and our obligations. Further, IPH and its direct and indirect subsidiaries present themselves to the public as separate entities.

On March 28, 2012, we entered into a put option agreement with AERG, which gave us the option to sell to AERG the Gas-Fired Facilities. Our original Put Option agreement with AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley (the “Put Option”). On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH (the “Transaction Agreement”), which was completed December 2, 2013 (the “Acquisition Date”). Immediately prior to Ameren’s entry into the Transaction Agreement with IPH on March 14, 2013, we exercised our option under the Put Option agreement with Medina Valley and received an initial payment of $100 million for the then pending sale of the Gas-Fired Facilities to Medina Valley. On October 11, 2013, Ameren received FERC approval

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for the divestiture of New AER to IPH and our sale of the Gas-Fired Facilities to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these Gas-Fired Facilities to Medina Valley and received additional after-tax cash proceeds of approximately $38 million. Medina Valley entered into an agreement to sell the Gas-Fired Facilities to Rockland Capital (the “Rockland Agreement”). The sale of the Gas-Fired Facilities to an affiliate of Rockland Capital closed on January 31, 2014. Under the Put Option, Medina Valley is obligated to pay us after-tax proceeds realized on the sale of the Gas-Fired Facilities in excess of $138 million, net of any indemnifications per the Rockland Agreement, within two years of January 31, 2014.

Genco has a PSA with IPM, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with IPRG. Under the PSAs, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity.

EEI has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that IPM pays for capacity is set annually based upon prevailing market prices. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a nonaffiliated party.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Ultimately, our sales are subject to market conditions for power. We principally use coal for fuel in our operations. The price of coal can fluctuate significantly because of the global economic and political environment, weather, supply and demand, and many other factors. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our facilities, operations and maintenance costs and capital investment are key factors that we seek to control to optimize our results of operations, financial position and liquidity.

Earnings Summary

Net loss attributable to Genco was $188 million and $33 million for 2013 and 2012, respectively. Net income attributable to Genco was $44 million for 2011.

2013 versus 2012

Earnings in 2013, compared with 2012, were adversely affected by a pretax impairment charge to earnings of $199 million to reflect the adjustment in the carrying values of the Gas-Fired Facilities to their fair value less cost to sell. While operating revenues remained relatively static in 2013 as compared to 2012, operating margin was lower, primarily as a result of higher purchased power. The increase in purchased power was related to satisfaction of sales to the DOE, which were partially offset by net MTM gains on fuel-related contracts. The 2013 period benefited from a reduction in other operations and maintenance expenses, primarily due to a curtailment gain realized on the restructuring of the EEI pension plan at the Acquisition Date, lower plant maintenance costs and reduced charges for cancelled projects. Additionally, interest charges decreased due to increased capitalized interest.

2012 versus 2011

Our earnings in 2012, compared with 2011, were adversely affected by reduced electric margins, which declined as a result of lower sales volumes, primarily due to lower realized prices. Another factor contributing to the net loss in 2012 was the pretax impairment charge of $70 million associated with the Elgin facility. Earnings in 2012 benefited from a reduction in other operations and maintenance expenses and depreciation expenses as a result of the December 2011 closure of the Meredosia and Hutsonville facilities.

For additional details regarding results of operations, including explanations of Operating Margin, Other Operations and Maintenance Expenses, Impairment and Other Charges, Depreciation and Amortization, Taxes Other Than Income Taxes, Interest Charges and Income Taxes, see the major headings below.

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Operating Margin

The following table presents the favorable (unfavorable) variations for operating margin from the previous year. Operating margin is defined as operating revenues less fuel and purchased power costs. The table covers the years ended December 31, 2013, 2012 and 2011. We consider operating margin a useful measure to analyze the change in profitability of our electric operations between periods. Operating margin, as defined above, is derived from GAAP measures presented on our statements of operations.

(amounts in millions)	2013 versus 2012			2012 versus 2011
Electric revenue change:
Sales volume	$	10		$	(218	)
Sales price changes, including hedge effect	(162		)	(42		)
Net gains from changes in MTM	—			3
Sales related to a large industrial customer	142			—
Other	6			(1		)
Total electric revenue change	(4		)	(258		)
Fuel and purchased power change:
Fuel:
Production volume and other	(5		)	101
Price variance	8			(23		)
Net gains (losses) from changes in MTM	25			(19		)
Sales and use tax settlement	(5		)	—
Purchased power and other	(140		)	54
Total fuel and purchased power change	(117		)	113
Net change in operating margin	$	(121	)	$	(145	)

2013 versus 2012

Operating margin decreased by $121 million, or 37%, in 2013 compared with 2012 primarily due to the following items:

• We experienced lower market prices associated with the Genco and EEI PSAs. The combined impact of lower market prices under both power supply agreements resulted in an unfavorable price variance, which decreased revenues by $162 million; decreases were offset by higher sales of $142 million related to the satisfaction of sale contracts to the DOE through IPM and an increase of $10 million in electric sales related to an increase in our facilities’ average capacity factor, 67% in 2013 compared to 62% in 2012.

• Increase in purchased power costs of $140 million related to the satisfaction of sale contracts to the DOE through IPM, partially offset by MTM gains on fuel-related contracts.

2012 versus 2011

Operating margin decreased by $145 million, or 31%, in 2012 compared with 2011 primarily due to the following items:

• Decreased facility utilization, primarily due to lower spot market prices, resulting in a decline in sales volumes. In addition, an EEI sales contract in 2011 was not supplied in 2012. Both of these combined to decrease revenues by $218 million. This decline was mitigated by a related $101 million decrease in production volume and other costs and a $54 million decrease in purchased power and other costs. Our facilities’ average capacity factor decreased to 62%, in 2012, compared with 71%, in 2011, because of lower power prices. The equivalent availability factor decreased to 85% in 2012, compared with 86% in 2011.

• Lower revenues allocated under the Genco PSA with IPM. There was a smaller pool of money to allocate because of lower market prices. We were allocated a lower percentage of revenues from the pool because of lower reimbursable expenses and lower levels of generation relative to AERG. We also experienced lower market prices associated with the EEI PSA. The combined impact of lower market prices under both power supply agreements resulted in an unfavorable price variance, which decreased revenues by $42 million.

• 3% higher fuel prices, primarily due to higher commodity costs associated with new coal supply agreements, decreased margin by $23 million.

• Net unrealized MTM activity primarily on fuel-related contracts, decreased margin by $16 million.

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses decreased by $43 million in 2013 compared with 2012, primarily because of a curtailment gain associated with EEI postretirement benefits of $26 million and lower EEI maintenance costs of $18 million as a result of reduced labor, benefit, and fuel additive expense, lower project cancellation expenses of $4 million, lower costs due to the effects of the shutdown of the Meredosia and Hutsonville facilities of $3 million and decreased expenses at the CTs of $1 million as a result of the sale to Medina Valley. Partially offsetting these decreases were increased non-labor maintenance expenses at our coal-fired facilities of $8 million due to higher outage expense.

Other operations and maintenance expenses decreased by $13 million in 2012 compared to 2011, primarily because maintenance costs decreased by $25 million as a result of the December 2011 closure of the Meredosia and Hutsonville facilities and fewer outages at our other facilities. Partially offsetting decreased maintenance costs were reduced net gains from property sales of $11 million between years and charges for cancelled projects in 2012 of $4 million.

Impairment and Other Charges

The following table summarizes impairment and other charges for the years ended December 31, 2013, 2012 and 2011:

(amounts in millions)	Long-lived Assets and Related Charges		Emission Allowances		Total
2013	$	199	$	—	$	199
2012	$	70	$	—	$	70
2011	$	34	$	1	$	35

Please read Note 1—Summary of Significant Accounting Policies and Note 11—Impairment and Other Charges for further discussion. The impairment charges did not result in a violation of any debt covenants or counterparty agreements.

After the impairment charge due to the loss on disposal of the Gas-Fired Facilities in 2013, we believe the carrying value of our long-lived assets exceeds their realizable fair value under current market conditions. We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs and other events or changes in circumstances that indicate that the carrying value of our facilities may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our facilities, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell our facilities. As of December 31, 2013, the carrying value of long-lived assets exceeded their realizable fair value by an amount in excess of $1 billion.

2013 versus 2012

Impairment and other charges increased by $129 million in 2013 as compared to 2012. We recorded a pretax charge to earnings of $199 million for 2013, to reflect the impairment of the Gas-Fired Facilities. The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower gas-fired facilities as the Elgin facility was previously impaired under held and used accounting guidance during the fourth quarter 2012.

2012 versus 2011

Impairment and other charges increased by $35 million in 2012 as compared to 2011. In December 2012, Ameren determined that it intended to, and it was probable that it would, exit its merchant generation business, of which we were a part. Based on the expectation of reduced financial support from Ameren, together with existing power and market conditions and cash flow requirements we estimated, at the time, it was more likely than not that we would sell our Elgin facility for liquidity purposes within two years. This change in assumption resulted in a pre-tax non-cash asset impairment charge of $70 million. This represented the increase in impairment and other charges when comparing 2012 to 2011.

Depreciation and Amortization

Depreciation and amortization expenses decreased by $5 million in 2013 compared with 2012, primarily due to a reduced depreciable base caused by the impairment of our facilities and the cessation of depreciation on the facilities held for sale. See Note 1—Summary of Significant Accounting Policies for further discussion.

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Depreciation and amortization expenses decreased by $11 million in 2012 compared to 2011, primarily because of a change in estimates related to asset retirement obligations and the closure of the Meredosia and Hutsonville facilities in December 2011.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased by $6 million in 2013 as compared to 2012 primarily due to lower ad valorem taxes related to the divestiture of gas assets in 2013 and slightly lower payroll taxes due to EEI restructuring at the Acquisition Date.

Taxes other than income taxes were comparable between 2012 and 2011.

Interest Charges

Interest charges decreased by $10 million in 2013 compared with 2012, primarily because of increased capitalized interest due to the Newton facility scrubber project and reduced amortization of credit facility fees.

Interest charges decreased by $11 million in 2012 compared with 2011, primarily because of increased capitalized interest due to the Newton facility scrubber project.

Income Taxes

The effective income tax rates were 26%, 42% and 42% for 2013, 2012 and 2011, respectively.

The effective rate was lower in 2013 compared with 2012 primarily as the result of the effects of the AER Acquisition on us, including loss of benefits from the existing pre-acquisition NOLs due to IRC Section 382 limits.

LIQUIDITY AND CAPITAL RESOURCES

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs.  Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations and cash on hand.

We are organized into a ring-fenced group in order to maintain corporate separateness from Dynegy and its other legal entities. We have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers.  Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons.  These provisions restrict the ability to move cash out of Genco without meeting certain requirements as set forth in the governing documents.

As of December 31, 2013, our liquidity consisted of $190 million of cash on hand.

Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. Please read Note 5—Long-Term Debt for further discussion on our indenture provisions. During the first quarter 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level until at least 2016. As a result, our ability to borrow additional funds from external, third-party sources is restricted. If an intercompany financing need were to arise, borrowings would be dependent on consideration by Dynegy of the facts and circumstances existing at that time. Should a financing need arise, our sources of liquidity include available cash on hand.

On December 2, 2013, our ability to borrow under Ameren’s money pool arrangement was terminated in connection with the AER Acquisition. In addition, the 2010 Genco Credit Agreement was terminated in November 2012 and not renewed. Please read Note 4—Short-Term Debt and Liquidity for further discussion regarding the 2010 Genco Credit Agreement.

On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the sale of our Gas-Fired Facilities to Medina Valley, an affiliate of Ameren. On October 11, 2013, we completed the sale of our Gas-Fired Facilities to Medina Valley and received an additional payment of $38 million. Based on current projections as of December 31, 2013, we expect operating cash flows and daily working capital needs to be sufficiently covered by our cash on hand in 2014.

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We cannot pay dividends on our common stock unless our actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of December 31, 2013, of operating results and cash flows in 2014 and 2015, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2014, December 31, 2014, June 30, 2015 or December 31, 2015. As a result, we were restricted from paying dividends as of December 31, 2013, and we expect to be unable to pay dividends until at least 2016. Please read Note 5—Long-Term Debt for further discussion on indenture provisions. We paid no dividends in 2013, 2012 or 2011.

The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2013, 2012 and 2011:

	Year Ended December 31,
(amounts in millions)	2013		2012			2011
Net cash provided by operating activities	$	51	$	139		$	215
Net cash provided by (used in) investing activities	$	110	$	(122	)	$	(141	)
Net cash provided by (used in) financing activities	$	4	$	—		$	(72	)

Cash Flows from Operating Activities

2013 versus 2012

Cash provided by operating activities decreased by $88 million in 2013 compared with 2012. Operating margin, as discussed in Results of Operations, decreased by $146 million, excluding impacts of non-cash MTM transactions. The following items partially offset the decrease in cash derived from operating margin during 2013, compared with 2012:

• A $50 million increase in income tax refunds primarily due to lower pretax book income and the full utilization of the 2013 net operating loss through the tax allocation agreement with Ameren and its subsidiaries that existed prior to the AER Acquisition.

• An $8 million decrease in interest payments.

2012 versus 2011

Cash provided by operating activities decreased by $76 million in 2012 compared with 2011. Operating margin, as discussed in Results of Operations, decreased by $129 million, excluding impacts of non-cash MTM transactions. The following items partially offset the decrease in cash from operating margin during 2012, compared with 2011:

• Accounts payable balances related to coal purchases increased $14 million, primarily due to increased purchases to support increased refined coal activity in 2012.

• A $6 million decrease in labor expenditures and a $5 million decrease in payments to contractors, primarily due to the 2011 Meredosia and Hutsonville facility closures.

• The receipt of $10 million for net coal transfers to refiners under agreements that began in late 2011. The coal will be purchased back from the refiners in a subsequent period.

• An $8 million decrease in coal inventory, primarily due to continued focus on inventory reductions, partially offset by increased coal prices.

Cash Flows from Investing Activities

2013 versus 2012

Cash provided by investing activities increased by $232 million in 2013 compared with 2012, primarily due to the proceeds from sales of properties of $138 million in 2013 as described above and a decrease in capital expenditures of $120 million primarily related to the Newton facility scrubber project, partially offset by a decrease in proceeds from repayment of net money pool advances of $20 million due to the AER Acquisition.

2012 versus 2011

Cash used in investing activities decreased by $19 million in 2012 compared with 2011, principally attributable to a change in net money pool advances offset by an increase in capital expenditures and a reduction in proceeds related to sales of properties. During 2012, capital expenditures exceeded net cash provided by operating activities by $36 million. The cash shortfall was funded by repayments of advances previously paid to Ameren’s money pool. In 2011, net cash provided by operating activities

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exceeded capital expenditures by $74 million, which allowed us to contribute $49 million to the money pool. In 2012, capital expenditures increased by $34 million primarily because of increased expenditures related to the scrubber project at the Newton facility, which more than offset a reduction in maintenance and upgrade project expenditures due to the timing of facility outages. In 2012, cash flows from investing activities benefited from the sales of assets for proceeds of $6 million, which resulted in a net $1 million pretax gain. In 2011, cash flows from investing activities benefited from property sale proceeds, principally attributable to $45 million received from the sale of our interest in the Columbia CT facility.

Capital Expenditures

Capital expenditures for the years ended December 31, 2013, 2012 and 2011 were $55 million, $175 million and $141 million, respectively. Capital expenditures principally consisted of facility upgrades to comply with environmental regulations. In 2013, 2012 and 2011, we spent $38 million, $141 million and $75 million, respectively, toward scrubber projects. Other capital expenditures were made principally to fund various facility upgrades.

We estimate the capital expenditures that will be incurred for 2014 are $53 million, of which $45 million are for compliance with known and existing environmental regulations and upgrades to existing coal facilities discussed below. The recoverability of our capital investments will depend on whether market prices for power change to reflect increased environmental costs for coal-fired energy facilities. Please read Outlook and also Note 10—Commitments and Contingencies for further discussion of the impact of declining power prices on our business.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any such changes could result in significant capital expenditures or losses being incurred, which could be material.

We will incur significant costs in future years to comply with existing and future federal and state regulations including those requiring the reduction of SO₂, NOx and mercury emissions from coal-fired facilities.

Please read Note 10—Commitments and Contingencies for further discussion of existing environmental laws and regulations that affect, or may affect, our facilities and capital costs in 2014 to comply with such laws and regulations, including CAIR, the MPS and the final MATS rule, as of December 31, 2013.

Cash Flows from Financing Activities

2013 versus 2012

Net cash provided by financing activities increased by $4 million in 2013 compared with 2012, primarily due to a capital contribution received from AER.

2012 versus 2011

Net cash used in financing activities decreased by $72 million in 2012 compared with 2011. In 2012, we met our working capital and investing requirements without utilizing financing. In 2011, we received a $28 million capital contribution from AER, our former parent, associated with a tax allocation agreement that benefited cash flows from financing activities and we utilized surplus net cash from operating activities to repay $100 million of short-term borrowing obligations.

Short-term Borrowings

Our liquidity needs are typically supported through the use of cash flows from operations and available cash on hand. The 2010 Genco Credit Agreement was terminated on November 14, 2012 and was not renewed. Prior to the AER Acquisition on December 2, 2013, we had borrowing access to a non-state-regulated subsidiary money pool arrangement among Ameren and certain of its subsidiaries. In connection with the AER Acquisition, our ability to borrow under such money pool arrangement was terminated.

Prior to the AER Acquisition, Ameren’s credit agreements were available for use, subject to applicable regulatory short-term borrowing authorizations, through direct short-term borrowings from Ameren and through a money pool agreement. Ameren had money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Ameren Services was responsible for operation and administration of the money pool agreements. However, in connection with the AER Acquisition, our access to Ameren credit agreements and our ability to borrow under such money pool arrangement was terminated.

Please read Note 4—Short-Term Debt and Liquidity for further discussion.

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Long-term Debt and Equity

For the years ended December 31, 2013 and 2012, there were no issuances of common stock, and no issuances, redemptions, repurchases or maturities of long-term debt. Please read Note 5—Long-Term Debt for further discussion.

Summarized Debt

The following table depicts our third party debt obligations as of December 31, 2013 and 2012:

(amounts in millions)	2013			2012
Unsecured obligations	$	825		$	825
Unamortized discount	(1		)	(1		)
Total Long-term debt, net	$	824		$	824

Indebtedness Provisions and Other Covenants

Please read Note 5—Long-Term Debt for further discussion of covenants and provisions contained in our indenture, and “Dividends” below regarding restrictions on dividends.

At December 31, 2013, we were in compliance with the provisions and covenants contained within our indenture. Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios as of and for the year ended December 31, 2013:

	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio (a)	≥1.75	1.57
Additional indebtedness interest coverage ratio (b)	≥2.50	1.57
Additional indebtedness debt-to-capital ratio (b)	≤60%	52	%

_______________________________________

(a) As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

(b) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Operating results and operating cash flows are significantly affected by changes in market prices for power, which have shown increases as compared to the past few years. Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. During the first quarter 2013, our interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and we expect the ratio to remain less than this minimum level until at least 2016. As a result, our ability to borrow additional funds from external, third-party sources is restricted.

Dividends

Our indenture includes restrictions that prohibit payments of dividends on our common stock. Specifically, dividends cannot be paid unless the actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections of operating results and cash flows in 2014 and 2015 as of December 31, 2013, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2014, December 31, 2014, June 30, 2015 or December 31, 2015. As a result, we were restricted from paying dividends as of December 31, 2013, and we expect to be unable to pay dividends until at least 2016. Please read Note 5—Long-Term Debt for further discussion on indenture provisions. We paid no dividends in 2013, 2012 or 2011.

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Contractual Obligations

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.      

The following table summarizes the contractual obligations of the Company and its consolidated subsidiaries as of December 31, 2013. Cash obligations reflected are not discounted and do not include accretion or dividends.

	Expiration by Period
(amounts in millions)	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long-term debt (including current portion)	$	825	$	—	$	—	$	300	$	525
Interest payments on debt	631		59		117		117		338
Coal commitments	366		158		175		33		—
Coal transportation	279		37		48		50		144
Operating leases	3		1		1		1		—
Pension funding obligations	15		4		7		4		—
Other obligations	7		3		—		—		4
Total contractual obligations	$	2,126	$	262	$	348	$	505	$	1,011

Long-Term Debt (Including Current Portion).  Amounts do not include unamortized discounts. Please read Note 5—Long-Term Debt for further discussion.

Interest Payments on Debt.  Interest payments on debt represent estimated periodic interest payment obligations. Please read Note 5—Long-Term Debt for further discussion.

Coal Commitments.  At December 31, 2013, we had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect our minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation.  At December 31, 2013, we had long-term coal transportation contracts in place. We also had long-term rail car leases in place. The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts.

Operating Leases.  Operating leases include minimum lease payment obligations associated with office leases.

Pension Funding Obligations. Amounts include our minimum required contributions to our defined benefit pension plans through 2023 as determined by our actuary and are subject to change based on actual results of the plan. Please read Note 6—Retirement Benefits for further discussion.

Other Obligations.  Other obligations include severance and retention obligations of $3 million as of December 31, 2013 in connection with a reduction in workforce. Amounts also include obligations of $4 million over the next 26 years under a facilities service agreement to compensate an affiliated entity for additions made on our electric generating facilities.

Commitments and Contingencies

Please read Note 10—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.

Off-Balance-Sheet Arrangements

At December 31, 2013, we did not have any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

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Credit Ratings

In carrying out our commercial business strategy, our current non-investment grade credit ratings have resulted and will likely continue to result in requirements that we either prepay obligations or post significant amounts of collateral to support our business.

The following table presents the principal credit ratings by Moody’s and S&P effective on the date of this report:

	Moody’s	S&P
Issuer/corporate credit rating	—	CCC+
Senior unsecured debt	B3	CCC+

A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

Collateral Postings

We use a portion of our capital resources in the form of cash to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices, price volatility and other factors. Additional collateral support for agreements entered into prior to December 2, 2013 will continue to be provided by Ameren for a period of two years after December 2, 2013 pursuant to the terms of the Transaction Agreement. Please read Note 2—Related Party Transactions for further discussion.

OUTLOOK

    As of December 31, 2013, we expected to have available generation from our coal-fired facilities of 24 million megawatthours in any given year. However, based on currently expected power prices, we expect to generate approximately 20 million megawatthours in 2014.     

As of March 12, 2014, our expected coal requirements are 97% contracted and 87% priced in 2014. Our forecasted coal requirements for 2015 are 50% contacted and 30% priced. Our coal transportation requirements are fully contracted and priced for the next several years. We will look to procure and price additional fuel opportunistically.

Through IPM, we commercialize our assets through a combination of physical participation in the MISO markets and bilateral capacity sales. The first zonal auction was held in March 2013. For the 2013-2014 planning year, capacity cleared at $1.05 per MW-day for all zones. This low clearing price was likely caused by excess capacity conditions prevailing in MISO for the term of the planning year. In the future, the potential retirement of marginal MISO coal capacity due to poor economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM could also affect MISO capacity and energy pricing. The results of the next zonal auction will be released in April 2014.

Through IPM, we also sell a portion of our capacity into the PJM control area. Capacity market prices within PJM are consistently higher than within MISO. In addition, PJM holds auctions several years in advance. Through IPM, we have sold capacity volumes for the 2015-2016 and 2016-2017 planning years. The next PJM auction is in May 2014 for the 2017-2018 planning year, and we intend to offer some of our capacity in that auction.

REGULATORY MATTERS

Please read Note 10—Commitments and Contingencies for further discussion.

ACCOUNTING MATTERS

Critical Accounting Estimates

Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

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Valuation of Long-Lived Assets and Asset Retirement Obligations

We periodically assess the carrying value of our long-lived assets to determine whether they are impaired. We also review for the existence of asset retirement obligations. If an asset retirement obligation is identified, we determine its fair value and subsequently reassess and adjust the obligation, as necessary.

Uncertainties Affecting Application

• Changes in business, industry, laws, technology, or economic and market conditions

• Valuation assumptions and conclusions, including an appropriate discount rate and terminal year earnings multiple

• Our assessment of market participants

• Estimated useful lives or duration of ownership of our significant long-lived assets

• Actions or assessments by our regulators

• Identification of an asset retirement obligation and assumptions about the timing of asset removals

Basis for Judgment

Whenever events or changes in circumstances indicate a valuation may have changed, we use various methodologies that we believe market participants would use to determine valuations and discounted, undiscounted, and probabilistic discounted cash flow models with multiple operating scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and interviews. Please read Note 1—Summary of Significant Accounting Policies for further discussion of quantification of our asset retirement obligations. Please read Impairment and Other Charges in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 11—Impairment and Other Charges for further discussion of our long-lived asset impairment evaluation and charges recorded.

Benefit Plan Accounting

Based on actuarial calculations, we accrue costs of providing future employee benefits. Please read Note 6—Retirement Benefits for further discussion.

Uncertainties Affecting Application

• Future rate of return on pension and other plan assets

• Valuation inputs and assumptions used in the fair value measurements of plan assets excluding those inputs that are readily observable

• Interest rates used in valuing benefit obligations

• Health care cost trend rates

• Timing of employee retirements and mortality assumptions

• Changing market conditions that may affect investment and interest rate environments

• Impacts of the health care reform legislation enacted in 2010

Basis for Judgment

Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable.

Accounting for Contingencies

We make judgments and estimates in recording and disclosing liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. A gain contingency is not recorded until realized or realizable.

Uncertainties Affecting Application

• Estimating financial impact of events

• Estimating likelihood of various potential outcomes

• Regulatory and political environments and requirements

• Outcome of legal proceedings, settlements or other factors

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• Changes in regulation, expected scope of work, technology or timing of environmental remediation

Basis for Judgment

The determination of a loss contingency requires significant judgment as to the expected outcome of each contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider all available evidence including the expected outcome of potential litigation. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. Please read Note 10—Commitments and Contingencies for further discussion.

Accounting for Income Taxes

Based on authoritative accounting guidance, we record the provision for income taxes, deferred tax assets and liabilities and a valuation allowance against net deferred tax assets, if any. Please read Note 7—Income Taxes for further discussion.

Uncertainties Affecting Application

• Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations

• Estimates of the amount and character of future taxable income

• Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled

• Effectiveness of implementing tax planning strategies

• Changes in income tax laws

• Results of audits and examinations of filed tax returns by taxing authorities

Basis for Judgment

The reporting of tax-related assets requires the use of estimates and significant management judgment. Deferred tax assets are recorded representing future effects on income taxes for temporary differences between the bases of assets for financial reporting and tax purposes. Although management believes current estimates for deferred tax assets are reasonable, actual results could differ from these estimates based on a variety of factors including change in forecasted financial condition and/or results of operations, change in income tax laws or enacted tax rates, the form, structure, and timing of asset or stock sales or dispositions, and results of audits and examinations of filed tax returns by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At any period end, and as new developments occur, management will reevaluate its tax positions. We were party to a tax allocation agreement with Ameren that provided for the allocation of consolidated tax liabilities. This tax allocation agreement specified that each party be allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. As a result of the AER Acquisition, we and our subsidiaries are now party to a tax sharing agreement with Dynegy. This agreement also provides that the amount of tax recognized is similar to that which would have been owed had we been separately subject to tax. Please read Note 7—Income Taxes for further discussion of the amount of deferred tax assets and uncertain tax positions recorded at December 31, 2013.

Impact of Future Accounting Pronouncements

Please read Note 1—Summary of Significant Accounting Policies for further discussion.

SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities have higher volatility and demand, respectively, in the summer cooling months. This trend may change over time as demand for electricity generation in the summer months increases. Further, to the extent that climate change may affect weather patterns, this could result in more extreme weather patterns which could impact demand for our products.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

Our risk management objective is to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies have been approved by our Board of Directors and are monitored by the CRCG.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.

Our revenues are primarily derived from the sales of electricity to IPM as described in Note 2—Related Party Transactions. At December 31, 2013, approximately $59 million of our accounts receivables are related party receivables from IPM. No other customer represents greater than 10% of our accounts receivables.

Commodity Price Risk

Our coal-fired facilities are considered baseload units, and as such our units generally have high capacity factors and will run around the clock. We are exposed to changes in market prices for power and the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies. If power prices were to decrease by 1% on economic generation for 2014 through 2018, earnings would decrease $29 million.

We limit our coal price exposure for generation by entering into term purchase agreements for PRB coal. Profitable operation of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates. We intend to secure a reliable coal supply while reducing exposure to commodity price volatility. Our coal transportation requirements are fully contracted and priced for the next several years. Transportation of PRB coal can also be affected by extreme weather, rail maintenance, and accidents, slowing or stopping the delivery from the mine to the facility. The following table shows the percentage of our coal and coal transportation requirements that have been contracted for the five-year period 2014 through 2018:

	2014		2015		2016 - 2018
Coal	97	%	50	%	24	%
Coal transportation	100	%	100	%	76	%

If our coal and coal transportation costs were to increase by 1% on any physical requirements not currently contracted and priced for the five-year period 2014 through 2018 our earnings would decrease by $5 million and $2 million, respectively.

Please read Power Generation under Part I, Item 1, for the percentages of our historical needs satisfied by coal, natural gas, and oil. Also please read Note 10—Commitments and Contingencies for further discussion.

26

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Illinois Power Generating Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Illinois Power Generating Company and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 28, 2014

27

ILLINOIS POWER GENERATING COMPANY CONSOLIDATED BALANCE SHEETS (in millions, except share data)
	December 31, 2013			December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	190		$	25
Advances to money pool	—			27
Accounts receivable – affiliates	59			70
Miscellaneous accounts receivable	18			20
Materials and supplies	78			85
Other current assets	18			28
Assets held for sale	—			364
Total Current Assets	363			619
Property, plant and equipment, net	1,873			1,887
Other assets	28			26
Total Assets	$	2,264		$	2,532
LIABILITIES AND EQUITY
Current Liabilities
Accounts and wages payable	$	45		$	54
Accounts payable – affiliates	—			12
Current portion of tax payable	—			6
Taxes accrued	12			14
Interest accrued	10			12
Current accumulated deferred income taxes, net	19			—
Other current liabilities	8			17
Liabilities held for sale	—			25
Total Current Liabilities	94			140
Long-term debt	824			824
Deferred Credits and Other Liabilities
Accumulated deferred income taxes, net	520			334
Tax payable	—			39
Asset retirement obligations	43			59
Pension and other postretirement benefits	18			92
Other deferred credits and liabilities	2			16
Total Deferred Credits and Other Liabilities	583			540
Commitments and Contingencies (Note 10)
Stockholder’s Equity
Common stock, no par value, 10,000 shares authorized; 2,000 shares outstanding	—			—
Other paid-in capital	551			656
Retained earnings	216			404
Accumulated other comprehensive loss	(11		)	(40		)
Total Illinois Power Generating Company Stockholder’s Equity	756			1,020
Noncontrolling Interest	7			8
Total Equity	763			1,028
Total Liabilities and Equity	$	2,264		$	2,532

The accompanying notes are an integral part of these consolidated financial statements.

28

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2013			2012			2011
Operating Revenues (Note 1)	$	804		$	808		$	1,066
Operating Expenses:
Fuel	459			482			541
Purchased power	141			1			55
Other operations and maintenance	123			166			179
Impairment and other charges	199			70			35
Depreciation and amortization	80			85			96
Taxes other than income taxes	15			21			21
Total operating expenses	1,017			825			927
Operating Income (Loss)	(213		)	(17		)	139
Other Income and Expenses:
Miscellaneous income	1			1			1
Miscellaneous expense	—			1			—
Total other income	1			—			1
Interest Charges	42			52			63
Income (Loss) Before Income Tax	(254		)	(69		)	77
Income Tax Expense (Benefit) (Note 7)	(65		)	(29		)	32
Net Income (Loss)	(189		)	(40		)	45
Less: Net Income (Loss) Attributable to Noncontrolling Interest	(1		)	(7		)	1
Net Income (Loss) Attributable to Illinois Power Generating Company	$	(188	)	$	(33	)	$	44

The accompanying notes are an integral part of these consolidated financial statements.

29

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)

	Year Ended December 31,
	2013			2012			2011
Net Income (Loss)	$	(189	)	$	(40	)	$	45
Other Comprehensive Income (Loss), Net of Tax:
Reclassification adjustments for derivative losses included in net income (loss), net of income taxes	1			1			1
Pension and other postretirement benefit plan activity, net of income tax expense (benefit) of $21, $28 and $(24), respectively	28			39			(34		)
Total other comprehensive income (loss), net of taxes	29			40			(33		)
Comprehensive Income (Loss)	(160		)	—			12
Less: Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest	(1		)	1			(4		)
Total Comprehensive Income (Loss) Attributable to Illinois Power Generating Company	$	(159	)	$	(1	)	$	16

The accompanying notes are an integral part of these consolidated financial statements.

30

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(189	)	$	(40	)	$	45
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment and other charges	199			70			35
Curtailment gain on pension and postretirement benefits	(26		)	—			—
Net mark-to-market (gain) loss on derivatives	(7		)	18			2
Depreciation and amortization	80			85			98
Deferred income taxes and investment tax credits, net	(1		)	(9		)	64
Other	—			9			(8		)
Changes in assets and liabilities:
Receivables	6			9			19
Materials and supplies	15			27			5
Accounts and wages payable	(14		)	6			(15		)
Other	(12		)	(36		)	(30		)
Net cash provided by operating activities	51			139			215
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(55		)	(175		)	(141		)
Proceeds from sales of properties	138			6			49
Money pool advances, net	27			47			(49		)
Net cash provided by (used in) investing activities	110			(122		)	(141		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Credit facility repayments, net	—			—			(100		)
Capital contribution from parent	4			—			28
Net cash provided by (used in) financing activities	4			—			(72		)
Net change in cash and cash equivalents	165			17			2
Cash and cash equivalents at beginning of year	25			8			6
Cash and cash equivalents at end of year	$	190		$	25		$	8
Cash Paid (Refunded) During the Year:
Interest (net of $18, $13 and $3 capitalized, respectively)	$	41		$	49		$	60
Income taxes, net	$	(65	)	$	(15	)	$	(25	)
Noncash investing and financing activities:
Capital contributions from parent	$	72		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

31

ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY

(in millions)

	December 31,
	2013			2012			2011
Common Stock	$	—		$	—		$	—
Other Paid-in Capital:
Beginning of year	656			653			649
Capital contribution from former parent	76			—			4
Adjustments to tax NOLs and other attributes from acquisition	(178		)	—			—
Other	(3		)	3			—
Other paid-in capital, end of year	551			656			653
Retained Earnings:
Beginning of year	404			437			393
Net income (loss) attributable to Illinois Power Generating Company	(188		)	(33		)	44
Retained earnings, end of year	216			404			437
Accumulated Other Comprehensive Loss:
Beginning of year	(40		)	(72		)	(44		)
Other comprehensive income (loss)	29			32			(28		)
Total accumulated other comprehensive loss, end of year	(11		)	(40		)	(72		)
Total Illinois Power Generating Company Stockholder’s Equity	756			1,020			1,018
Noncontrolling Interest:
Beginning of year	8			7			11
Net income (loss) attributable to noncontrolling interest holder	(1		)	(7		)	1
Other comprehensive income (loss) attributable to noncontrolling interest holder	—			8			(5		)
Noncontrolling interest, end of year	7			8			7
Total Equity	$	763		$	1,028		$	1,025

The accompanying notes are an integral part of these consolidated financial statements.

32

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

We are an electric generation subsidiary of IPH, which is an indirect wholly-owned subsidiary of Dynegy. We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois.

We have an 80% ownership interest in EEI. EEI operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois and Kentucky. We also consolidate our wholly-owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes. All significant intercompany transactions have been eliminated.

Our accounting policies conform to GAAP. Financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. Our financial condition at December 31, 2013 and 2012 and our results of operations for each of the years ended December 31, 2013, 2012 and 2011 are presented on a comparable basis. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.

On December 2, 2013, we were acquired by IPH, an indirect wholly-owned subsidiary of Dynegy. In connection with the AER Acquisition, Ameren retained certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. Ameren forgave certain liabilities related to pre-acquisition activities, and retained existing AROs, which were recorded as a capital contribution totaling $72 million. We did not apply “push-down accounting” as a result of the AER Acquisition which would require the adjustment of assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. Our approximately $825 million in aggregate principal amount of long-term notes payable remain outstanding as an obligation of Genco. IPH and its direct and indirect subsidiaries, including Genco, are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries, for the purpose of minimizing risk of claims against Dynegy for IPH’s and our obligations. We have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers.  Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons.  See below and Note 2—Related Party Transactions, Note 4—Short-Term Debt and Liquidity, Note 6—Retirement Benefits, Note 7—Income Taxes and Note 10—Commitments and Contingencies for the impacts on these consolidated financial statements as a result of the AER Acquisition.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.

Materials and Supplies

Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies at December 31, 2013 and 2012:

	Year Ended December 31,
(amounts in millions)	2013		2012
Fuel (a)	$	45	$	48
Other materials and supplies	33		37
Total	$	78	$	85

__________________________________________

(a) Consists of coal for 2013 and coal and natural gas for 2012.

Property, Plant and Equipment

The cost of additions to and betterments of units of property, plant and equipment are capitalized. The cost includes labor, material, applicable taxes, and overhead. Interest incurred during construction is capitalized as a cost of assets. Expenditures for major installations, replacements and improvements or betterments are capitalized and depreciated over the expected life cycle.

33

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Expenditures for maintenance, repairs and minor renewals to maintain the operating condition of our assets are expensed. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred that do not constitute legal obligations are generally expensed as incurred. Please read Asset Retirement Obligations below and Note 3—Property, Plant and Equipment, for further discussion.

Depreciation

Depreciation is provided using the straight-line method over the estimated service lives of the assets, ranging from 1 to 36 years. Our provision for depreciation in 2013, 2012 and 2011 has an average depreciable cost of approximately 3%.

The estimated economic service lives of our asset groups are as follows:

Asset Group	Range of Years
Power generation facilities	1 to 30
Environmental upgrades	10 to 30
Buildings and improvements	7 to 36
Office and other equipment	2 to 15

Intangible Assets

We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

At December 31, 2013 and 2012, intangible assets consisted of emission allowances. The book value of emission allowances was less than $1 million at the end of both years. Emission allowances are charged to fuel expense as they are used in operations. Amortization expense based on usage of emission allowances, net of gains from sales, excluding intangible asset impairment charges discussed below, were less than $1 million, $1 million and $2 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Please read Note 11—Impairment and Other Charges for further discussion.

Impairment of Long-lived Assets

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the carrying value exceeds its fair value less cost to sell. Please read Note 11—Impairment and Other Charges for further discussion.

Environmental Costs

Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.

Unamortized Debt Discount, Premium and Expense

Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.

Operating Revenue

Revenue is earned from the facilities based on generation for the sale of energy and the sale of capacity. Operating revenue for electric service is recorded based on net generation in accordance with our PSA with IPM. Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative.

Income Taxes

Upon the AER Acquisition, we were acquired in a transaction that resulted in an “ownership change,” as defined under IRC Section 382. Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of

34

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized is similar to that which would have been owed had we been separately subject to tax.

Upon the closing of the AER Acquisition, we are included in the consolidated federal and state returns of Dynegy. Genco and Dynegy have entered into a new tax sharing agreement. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis, as defined in the agreement. Under IRC Section 382, we are subject to a limitation in the amount of NOLs that could be used in any one year following this ownership change. Further, we are subject to a worthless stock loss deduction equal to Ameren’s tax basis in our stock prior to the AER Acquisition. Accordingly, we determined that our pre-acquisition NOLs are unlikely to be used against future taxable income and the estimated benefits therefrom have been written down to zero. We have also recorded the effects of a reduction of other tax attributes, totaling $433 million. These adjustments to our NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $178 million and a reduction to our income tax benefit for 2013 in the amount of $39 million. Please read Note 7—Income Taxes for further discussion.

We use an asset and liability approach for our financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.

Noncontrolling Interest

Noncontrolling interest is comprised of the 20% of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheet.    

Accounting Changes and Other Matters

The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact us.

Accounting Standards Adopted

Disclosures about Fair Value Measurements. In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. We adopted this guidance for the first quarter 2012. Please read Note 9—Fair Value Measurements for further discussion.

Presentation of Comprehensive Income.In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in separate but consecutive statements. This guidance was effective for us beginning in the first quarter 2012 with retroactive application required. The implementation of the amended guidance did not affect results of operations, financial position, or liquidity. In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments did not affect our results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance was effective for us beginning in the first quarter 2013 on a prospective basis.

Disclosures about Offsetting Assets and Liabilities.In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments did not affect our results of operations, financial positions or liquidity, as this guidance only requires additional disclosures. This guidance was effective for us beginning in the first quarter 2013 with retrospective application required.

35

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounting Standards Not Yet Adopted

Presentation of Unrecognized Tax Benefits. In July 2013, the FASB issued ASU 2013-11-Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.  The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes.  When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets.  The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted.  We are currently assessing the future impact of this update, but we do not anticipate a material impact on our financial condition, results of operations or cash flows.         

Asset Retirement Obligations

Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. We have recorded AROs for retirement costs associated with asbestos removal, river structures and CCR storage facilities.

The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the years ended December 31, 2012 and 2013:

(amounts in millions)
Balance at December 31, 2011	$	61
Liabilities incurred	2
Liabilities settled	(5		)
Accretion in 2012	4
Change in estimates	(3		)
Balance at December 31, 2012	59
Liabilities incurred	3
Liabilities settled (a)	(28		)
Accretion in 2013	4
Change in estimates	5
Balance at December 31, 2013	$	43

__________________________________________

(a) Under the terms of the agreement entered into on March 14, 2013 to divest New AER to IPH, Ameren retained the existing AROs associated with the closure of the Meredosia and Hutsonville facilities, which were estimated at $28 million as of the date of divestiture, December 2, 2013.

Employee Separation and Other Charges

In each of the past three years, employee separation programs were initiated to reduce positions under the terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of $3 million, $1 million and $4 million in 2013, 2012 and 2011, respectively. The 2013 and 2012 charges were recorded in “Other operations and maintenance” expense on the consolidated statements of operations. The 2011 charge related to the closure of the Meredosia and Hutsonville facilities and was recorded in “Impairment and other charges” on the consolidated statement of operations. Please read Note 11—Impairment and Other Charges for further discussion. In 2014, we expect to payout approximately $3 million of severance benefits to affected employees.

36

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Sales

We determined that the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”) first qualified for held for sale presentation beginning March 14, 2013. Therefore, beginning in the first quarter 2013, we segregated and reclassified the assets and liabilities associated with these Gas-Fired Facilities and presented them separately as held for sale at December 31, 2012. The operating results of the Gas-Fired Facilities did not qualify for discontinued operations presentation because we continue to sell power into the same markets with our remaining generation assets. As further discussed below, these facilities were sold prior to December 31, 2013 and there were no assets and liabilities held for sale on our consolidated balance sheet at December 31, 2013. The following table presents the components of assets and liabilities held for sale on our consolidated balance sheet at December 31, 2012:

(amounts in millions)	December 31, 2012
Assets held for sale
Materials and supplies	$	12
Mark-to-market derivative assets	4
Property, plant and equipment, net	348
Total assets held for sale	$	364
Liabilities held for sale
Accounts and wages payable	$	9
Taxes accrued	3
Mark-to-market derivative liabilities	3
Asset retirement obligations	10
Total liabilities held for sale	$	25

As a result of the assets and liabilities associated with the Gas-Fired Facilities meeting the held for sale criteria during 2013, we evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value less cost to sell. The estimated fair value was determined by reference to the amended put option agreement, the asset purchase agreement with Medina Valley, and the transaction agreement with IPH (as further described below and in Note 2—Related Party Transactions). We recorded a pretax charge to earnings of $199 million for 2013, to reflect the impairment of the Gas-Fired Facilities. The 2013 impairment recorded was primarily related to the Gas-Fired Facilities as the Elgin facility was previously impaired (pretax charge to earnings of $70 million) under held and used accounting guidance during the fourth quarter 2012. The 2013 impairment charge to earnings was recorded as an impairment of “Property, plant and equipment, net” within the components of assets held for sale shown above, and “Impairment and other charges” in our consolidated statement of operations for 2013. Please read Note 11—Impairment and Other Charges for further discussion. For 2013, we recorded an $82 million income tax benefit as a result of the impairment.

These assets and liabilities held for sale were measured at fair value on a nonrecurring basis, based on the cash proceeds of $138 million, which is an input classified as Level 3 within the fair value hierarchy.

Effective with our conclusion in March 2013 that the Gas-Fired Facilities met the criteria for held for sale presentation, we suspended recording depreciation on these facilities.

On March 28, 2012, we entered into a put option agreement with AERG, which gave us the option to sell to AERG the Gas-Fired Facilities. Our original Put Option agreement with AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley (the “Put Option”). On March 14, 2013, immediately prior to Ameren’s entry into the Transaction Agreement with IPH, we exercised our option under the put option agreement with Medina Valley and received an initial payment of $100 million with respect to the sale of the Gas-Fired Facilities to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and our sale of the Gas-Fired Facilities to Medina Valley. Immediately after receipt of FERC approval, we completed the sale of these Gas-Fired Facilities to Medina Valley and received additional cash proceeds of approximately $38 million. Medina Valley entered into an agreement to sell the Gas-Fired Facilities with Rockland Capital (the “Rockland Agreement”). The sale of the Gas-Fired Facilities to an affiliate of Rockland Capital closed on January 31, 2014. Under the Put Option, Medina Valley is obligated to pay us after-tax proceeds realized on the sale of the Gas-Fired Facilities in excess of $138 million, net of any indemnifications per the Rockland Agreement, within two years of January 31, 2014.

37

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In June 2011, we completed the sale of our remaining interest in the Columbia CT facility to the city of Columbia, Missouri.  We received cash proceeds of $45 million and recognized an $8 million pretax gain from the sale. In 2011, we sold additional property and assets for cash proceeds of $4 million, which resulted in pretax gains of $4 million.    

NOTE 2—RELATED PARTY TRANSACTIONS

We have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Below are the material related party agreements.

Amended Put Option Agreement

On March 28, 2012, we entered into a put option agreement with AERG which gave us the option to sell to AERG all, but not less than all, of the Gas-Fired Facilities for the greater of $100 million or the fair market value of the facilities. On March 14, 2013, this put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley, an affiliate of Ameren. As discussed in Note 1—Summary of Significant Accounting Policies, this option was exercised on March 14, 2013, resulting in the asset purchase agreement with Medina Valley.

Power Supply Agreements

The following table presents the amount of physical power sales and purchases under our related party electric PSAs with IPM, including EEI’s PSA with IPM, in gigawatthours:

	Year Ended December 31,
	2013	2012	2011
Genco sales to IPM	12,111	11,933	14,293
EEI sales to IPM	6,856	6,421	7,633
EEI purchases from IPM	29	22	886

Genco has a PSA with IPM, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with IPRG. Under the PSAs, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice. On February 26, 2014, Genco also entered into a collateral agreement with IPM pursuant to which Genco provides collateral to IPM to secure obligations of IPM applicable to Genco’s assets. There have been no amounts provided under this agreement to date.

EEI has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. The price that IPM pays for capacity is set annually based upon prevailing market prices. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a nonaffiliated party. This PSA will continue through May 31, 2016.

Support Services Agreements

Prior to the AER Acquisition, Ameren Services provided support services to its affiliates, including us. The costs of support services, including wages, employee benefits, professional services, and other expenses, were based on, or were an allocation of, actual costs incurred. In addition, we provided affiliates, primarily Ameren Services, with access to our facilities for administrative purposes. The cost of the rent and facility services were based on, or were an allocation of, actual costs incurred.

Upon the AER Acquisition, Dynegy and certain of its subsidiaries (collectively, the “Providers”) began providing certain services (the “Services”) to IPH, and certain of its consolidated subsidiaries (collectively, the “Recipients”), which includes us and EEI.

The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the service agreements. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreements, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this allocation methodology is a reasonable method of allocating

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the costs of the Services to us and provides an appropriate reflection of the costs we would have incurred if we were operated as an unaffiliated entity.

Tax Sharing Agreement

Upon the AER Acquisition, we are included in the consolidated tax returns of Dynegy. Under U.S. federal income tax law, Dynegy files consolidated income tax returns for itself and its subsidiaries. Dynegy is responsible for the federal tax liabilities of its subsidiaries which include the income and business activities of the ring-fenced entities and Dynegy’s other affiliates.  Prior to the AER Acquisition, we are included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized was similar to that which would have been owed had we been separately subject to tax. Genco and Dynegy have entered into a new tax sharing agreement that also provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement. As of December 31, 2013, we owed approximately $1 million to Dynegy pursuant to the new tax sharing agreement.

Gas Sales and Transportation Agreement

Prior to the AER Acquisition, under a gas transportation agreement, we acquired gas transportation services from Ameren Missouri that were expected to expire in February 2016. In connection with the AER Acquisition, we no longer have this agreement.

Employee Transfer

Through the end of 2012, some Ameren Services employees were included within AER’s business services group, which provided back office, controller, pricing, analytical support, engineering services, and selected information technology services for AER and its subsidiaries. On December 31, 2012, 74 of these employees were transferred to us from Ameren Services through an internal reorganization. In connection with the AER Acquisition, these support services were no longer provided to AER subsidiaries.

Intercompany Transfers

In 2012, we transferred various assets from our Hutsonville and Meredosia facilities to AERG. Both of the facilities were retired in 2011. We received cash proceeds in the amount of $3 million. The transfer of the assets was accounted for as a transaction between entities under common control; therefore, we did not recognize a gain on the transfer, but recognized an increase to other paid in capital for the amount of the proceeds.

Intercompany Sales

In 2012, we completed the sale of land for cash proceeds of $2 million to ATXI (Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets). We recognized a $2 million gain from the sale.

Money Pool

On December 2, 2013, our ability to borrow under Ameren’s non-state-regulated subsidiary money pool arrangement was terminated in connection with the AER Acquisition. Please read Note 4—Short-Term Debt and Liquidity for further discussion of affiliate borrowing arrangements.

Summary of Related Party Transactions

The following table presents the impact of related party transactions. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4—Short-Term Debt and Liquidity.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		Year Ended December 31,
(amounts in millions)	Income Statement Line Item	2013		2012		2011
Genco and EEI power supply agreements with IPM	Operating Revenues	$	709	$	804	$	1,006
Natural gas sales to Medina Valley (a)	Operating Revenues	—		1		3
Services provided to AER affiliates	Operating Revenues	6		—		—
Total Operating Revenues		$	715	$	805	$	1,009
Ameren Missouri gas transportation agreement	Fuel	$	1	$	1	$	1
EEI power supply agreement with IPM	Purchased Power	$	66	$	1	$	36
Support services agreement	Other Operations and Maintenance	$	13	$	21	$	19
Money pool borrowings (advances)	Interest (Charges) Income	(b)		(b)		(b)

__________________________________________

(a) Natural gas sold at fair value.

(b) Amount less than $1 million.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

A summary of our property, plant and equipment is as follows:

(amounts in millions)	December 31, 2013			December 31, 2012
Property, plant and equipment	$	2,551		$	2,787
Less: Accumulated depreciation and amortization	(1,027		)	(1,192		)
	1,524			1,595
Construction work in progress	349			292
Property, plant and equipment, net	$	1,873		$	1,887

Please read Note 11—Impairment and Other Charges for further discussion regarding non-cash long-lived asset impairments. The accrued capital expenditures at December 31, 2013, 2012 and 2011 were $3 million, $3 million and $13 million, respectively, which represent non-cash investing activity excluded from the statements of cash flows.

NOTE 4—SHORT-TERM DEBT AND LIQUIDITY

On November 14, 2012, the 2010 Genco Credit Agreement was terminated and not renewed. There was no borrowing activity under the 2010 Genco Credit Agreement, prior to its termination, for the year ended December 31, 2012. On December 2, 2013, our ability to borrow under Ameren’s non-state-regulated subsidiary money pool arrangement was terminated in connection with the AER Acquisition. On March 14, 2013, we amended and exercised our option to sell our three natural Gas-Fired Facilities to Medina Valley and received an initial payment of $100 million. On October 11, 2013, we completed the sale of our Gas-Fired Facilities to Medina Valley and received an additional payment of $38 million.  With the additional liquidity received through such sales, our financing sources are estimated to be adequate to support our operations in 2014. Please read Note 1—Summary of Significant Accounting Policies for further discussion regarding the asset sales.

Money Pool

Ameren, Genco’s former parent, established a money pool to coordinate and to provide short-term cash and working capital to its subsidiaries. Our ability to access funding from the Ameren and Ameren Missouri’s $1 billion multiyear senior unsecured credit agreement, Ameren and Ameren Illinois’ $1.1 billion multiyear senior unsecured credit agreement and Ameren’s commercial paper programs through a money pool agreement was terminated in connection with the AER Acquisition. Prior to such termination, when receiving a loan under the money pool agreement, we were required to repay the principal amount of such loan, together with accrued interest. The rate of interest depended on the composition of internal and external funds in the money pool. The average interest rate for borrowing under the money pool prior to the termination of our access to it for the year ended December 31, 2012 was 0.61%, and there were no borrowings for the year ended December 31, 2013. During the year ended

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, Genco received less than $1 million of interest income from money pool advances. Please read Note 2—Related Party Transactions for further discussion of the amount of interest income and expense from the money pool arrangements prior to the termination of our access to it, for the years ended December 31, 2013, 2012 and 2011.

NOTE 5—LONG-TERM DEBT

The following table presents our long-term debt outstanding:

(amounts in millions)	December 31, 2013			December 31, 2012
Unsecured notes:
Senior notes Series F 7.95% due 2032	$	275		$	275
Senior notes Series H 7.00% due 2018	300			300
Senior notes Series I 6.30% due 2020	250			250
Total long-term debt, gross	825			825
Less: Unamortized discount	(1		)	(1		)
Less: Maturities due within one year	—			—
Long-term debt, net	$	824		$	824

Aggregate maturities of the principal amounts of all long-term indebtedness, excluding unamortized discounts, as of December 31, 2013 are as follows: 2014—zero, 2015—zero, 2016—zero, 2017—zero, 2018—$300 million and thereafter—$525 million.

Indenture Provisions and Other Covenants

We are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive and (3) there is no self-dealing on the part of corporate officials.

At December 31, 2013, we were in compliance with the provisions and covenants contained within our indenture. Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios:

	Required Ratio
Restricted payment interest coverage ratio (a)	≥1.75
Additional indebtedness interest coverage ratio (b)	≥2.50
Additional indebtedness debt-to-capital ratio (b)	≤60%

_______________________________________

(a) As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

(b) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Our debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.

Based on December 31, 2013 results, our interest coverage ratios are less than the minimum ratios required to pay dividends and borrow additional funds from external, third-party sources. Based on our projections, we expect that our interest coverage ratios will be less than the minimum ratios required to pay dividends and incur additional third-party indebtedness until at least 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In order for us to issue securities in the future, we will have to comply with all applicable requirements in effect at the time of any such issuances.

Our indenture provides that dividends cannot be paid unless the actual interest coverage ratio for our most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections of operating results and cash flows in 2014 and 2015 as of December 31, 2013, we did not believe that we would achieve the minimum interest coverage ratio necessary to pay dividends on our common stock for each of the subsequent four six-month periods ending June 30, 2014, December 31, 2014, June 30, 2015, or December 31, 2015. As a result, we were restricted from paying dividends as of December 31, 2013, and we expect to be unable to pay dividends until at least 2016. No dividends were paid to our then-parent AER, prior to the AER Acquisition, in 2013, 2012, or 2011, nor to our parent subsequent to the AER Acquisition, IPR in 2013.

Off-Balance Sheet Arrangements

At December 31, 2013, we had no off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance sheet financing arrangements in the near future.

NOTE 6—RETIREMENT BENEFITS

We offer defined benefit pension and postretirement benefit plans covering our employees. Our employees and retirees, excluding EEI employees and retirees, participated in Ameren’s single-employer pension and other postretirement plans through December 1, 2013, prior to the AER Acquisition. Effective December 2, 2013, our employees and retirees, excluding EEI employees and retirees, participate in Dynegy’s single-employer pension and other postretirement plans. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and postretirement balances and disclosures. We use a measurement date of December 31 for our pension and postretirement benefit plans.

As a result of the AER Acquisition, Ameren retained the pension obligations associated with the current and former employees of Genco and the postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans. Effective with the AER Acquisition, Dynegy assumed the postretirement benefit obligation for active union employees of New AER and its subsidiaries not eligible to retire based on the assumption of the collective bargaining agreements in place. Genco retained the pension and other postretirement benefit obligations associated with EEI’s current and former employees. As a result of the AER Acquisition, certain EEI employees were terminated which resulted in a curtailment gain of $26 million which was recorded in Other operations and maintenance in our consolidated statements of operations.

For our disclosures below, unless otherwise noted, we have reflected the obligations, plan assets, and costs associated with EEI’s pension and postretirement plans. Also reflected is an allocation of our share of obligations, plan assets, and costs associated with our participation in Ameren’s single-employer pension and postretirement plans through December 1, 2013 and Dynegy’s single-employer pension and postretirement plans for the period from December 2, 2013 through December 31, 2013. The allocation of obligations, plan assets, and costs from our participation in Ameren’s and Dynegy’s single-employer pension plan was based on our employees’ share of total pensionable salaries. The allocation of obligations, plan assets, and costs from our participation in Ameren’s and Dynegy’s single-employer postretirement plans was based on the number of our employees.

The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2013 and 2012. It also provides the amounts included in accumulated OCI at December 31, 2013 and 2012 that have not been recognized in net periodic benefit costs. These amounts include the funded status of EEI’s pension and postretirement plans as well as an allocation of our share of obligation and plan assets associated with our participation in Ameren’s and Dynegy’s single-employer pension and postretirement plans.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2013						2012
(amounts in millions)	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
Accumulated benefit obligation at end of year	$	89		N/A			$	251		N/A
Change in benefit obligation:
Net benefit obligation at beginning of year	$	251		$	93		$	239		$	150
Transfer of liability from (to) Ameren Services / Medina Valley (a)	(7		)	(2		)	13			2
Transfer of liability to Ameren (b)	(136		)	(33		)	—			—
Allocation of liability from Dynegy (c)	—			4			—			—
Service cost	5			2			5			3
Interest cost	10			3			10			6
Plan amendments (d)(e)	—			(4		)	(6		)	(75		)
Participant contributions	—			1			—			1
Actuarial (gain) loss	(11		)	(8		)	3			15
Curtailments (f)	—			1			2			(1		)
Benefits paid	(22		)	(7		)	(15		)	(8		)
Administrative expenses paid	(1		)	—			—			—
Net benefit obligation at end of year	89			50			251			93
Change in plan assets:
Fair value of plan assets at beginning of year	183			83			167			81
Transfer of assets from Ameren Services / Medina Valley (a)	(6		)	(1		)	9			2
Transfer of assets to Ameren (b)	(130		)	(21		)	—			—
Actual return on plan assets	36			12			11			7
Employer contributions	15			—			11			—
Participant contributions	—			1			—			1
Benefits paid	(22		)	(7		)	(15		)	(8		)
Administrative expenses paid	(1		)	—			—			—
Fair value of plan assets at end of year	75			67			183			83
Funded status	$	14		$	(17	)	$	68		$	10
Amounts recognized in the balance sheet consist of:
Noncurrent asset (g)	$	—		$	(21	)	$	—		$	(14	)
Current liability	—			—			—			—
Noncurrent liability	14			4			68			24
Net liability (asset) recognized	$	14		$	(17	)	$	68		$	10
Amounts (pretax) recognized in accumulated OCI consist of:
Net actuarial loss	$	17		$	44		$	73		$	59
Prior service cost (credit)	(3		)	(43		)	(10		)	(62		)
Total	$	14		$	1		$	63		$	(3	)

_________________________________________

(a) In October 2013, 52 employees from Genco were transferred to Ameren Services and Medina Valley through an internal reorganization. On December 31, 2012, 74 employees from Ameren Services were transferred to Genco through an internal reorganization.

(b) Effective with the AER Acquisition, Ameren retained the portion of Genco’s pension obligations associated with the current and former employees of Genco and the portion of Genco’s postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans.

(c) Amount represents the allocation of the obligation from our participation in Dynegy’s single-employer plans.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(d) Effective with the AER Acquisition, the EEI management postretirement plan was remeasured as a result of a reduction in employees participating in the postretirement plan. This remeasurement reduced the benefit obligation, resulting in the establishment of a prior service credit.

(e) In 2012, EEI's pension plan was amended to adjust the calculation of the future benefit obligation for all of its active management employees and certain union-represented employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and union-represented postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.

(f) Effective with the AER Acquisition, there was a reduction in employees who participated in the EEI management postretirement plan which resulted in a curtailment of the plan. EEI implemented an employee reduction program in 2012, which resulted in a curtailment of its pension and management postretirement benefit plans.

(g) The EEI union postretirement plan was over-funded as of December 31, 2013 and 2012 and the EEI management postretirement plan was over-funded as of December 31, 2013, which was included in our balance sheets in “Other assets.”

The following table presents the assumptions used to determine our benefit obligations at December 31, 2013 and 2012:

	Pension Benefits				Postretirement Benefits
	2013		2012		2013		2012
Discount rate at measurement date (a)	4.82	%	4.00	%	4.78	%	4.00	%
Increase in future compensation (a)	3.50	%	4.48	%	3.50	%	4.41	%
Ameren - Medical cost trend rate (initial)	N/A		N/A		N/A		5.00	%
Ameren - Medical cost trend rate (ultimate)	N/A		N/A		N/A		5.00	%
Ameren - Years to ultimate rate	N/A		N/A		N/A		0
EEI - Medical cost trend rate (initial)	N/A		N/A		7.75	%	7.96	%
EEI - Medical cost trend rate (ultimate)	N/A		N/A		4.50	%	4.50	%
EEI - Years to ultimate rate	N/A		N/A		10 years		15 years

_________________________________________

(a) A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2013. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans at December 31, 2012.

Ameren, Dynegy and EEI determine their discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for their plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations.  For each plan, a single discount rate is then determined that results in a discounted value of that plan's benefit payments that equates to the market value of the selected bonds.

Funding

Pension benefits are based on the employees’ years of service and compensation. The Dynegy, Ameren and EEI pension plans are funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, we expect to fund EEI’s pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. In 2014, we expect to make contributions of $4 million to EEI's pension plan. In the aggregate, we expect to make contributions of $15 million to EEI’s pension plan over the next five years. Dynegy will contribute the portion of their pension related to Genco employees. These amounts are estimates and may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations or any voluntary contributions.

The following table presents the cash contributions made to our defined benefit retirement plans during 2013, 2012 and 2011:

	Pension Benefits
(amounts in millions)	2013		2012		2011
Ameren allocation (a)	$	5	$	4	$	4
EEI	10		7		8
Total	$	15	$	11	$	12

_________________________________________

(a) Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plans.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. Employer contributions to our postretirement plans were less than $1 million for each year ended December 31, 2013, 2012 and 2011.

Investment Strategy and Policies

Since we received an allocation, not a specific assignment, of Ameren’s and Dynegy’s single-employer plan assets, the asset related disclosures below focus on EEI’s plan assets, which are all specifically assigned to us and were retained by us after the AER Acquisition. In connection with the AER Acquisition, as of December 2, 2013, Ameren retained all of the plan assets within its single-employer pension and postretirement plans.

EEI manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. EEI’s goal is to earn the highest possible return consistent with its tolerance for risk, which is monitored by EEI’s management and board of directors. EEI delegates investment management to specialists in each asset class. As appropriate, EEI provides its investment managers with guidelines that specify allowable and prohibited investment types and regularly monitor manager performance and compliance with investment guidelines.

The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, EEI adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. EEI will utilize an expected return on plan assets for its pension plan assets of 6.25% in 2014. EEI will utilize an expected return on plan assets for its postretirement plan assets of 6.50% for EEI union employees and 5.50% for EEI management employees in 2014.

EEI strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. EEI’s management develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity or debt). The diversification of assets is displayed in the target allocation table below. EEI’s management also routinely rebalances the plan assets to adhere to the diversification goals. The following table presents EEI’s target allocations for 2014 and EEI’s pension and postretirement plans’ asset categories as of December 31, 2013 and 2012.

Asset Category	Target Allocation 2014		Percentage of Plan Assets at December  31,
			2013		2012
Pension Plan:
Equity securities	60	%	61	%	59	%
Debt securities	40	%	39	%	38	%
Cash	—	%	—	%	3	%
Total	100	%	100	%	100	%
Postretirement Plans:
Equity securities	60	%	60	%	62	%
Debt securities	40	%	38	%	36	%
Cash	—	%	2	%	2	%
Total	100	%	100	%	100	%

Fair Value Measurements of Plan Assets

Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2013. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in OTC markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As described above, a portion of Dynegy’s pension plan assets is allocated to us as of December 31, 2013. The amount of Dynegy pension plan assets allocated to us for financial reporting purposes as of December 31, 2013, was less than $1 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2013:

(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	—	$	—	$	—	$	—
Equity securities:
U.S. large capitalization	—		26		—		26
U.S. small capitalization	—		14		—		14
International	—		6		—		6
Debt Securities	—		29		—		29
Total	$	—	$	75	$	—	$	75

As described above, a portion of Ameren’s pension plan assets was allocated to us as of December 31, 2012. The amount of Ameren pension plan assets allocated to us for financial reporting purposes as of December 31, 2012, was $117 million based on pensionable salaries. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI pension plan assets measured at fair value as of December 31, 2012:

(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	—	$	2	$	—	$	2
Equity securities:
U.S. large capitalization	—		22		—		22
U.S. small capitalization	—		12		—		12
International	—		5		—		5
Debt securities	—		25		—		25
Total	$	—	$	66	$	—	$	66

As described above, a portion of Dynegy’s postretirement plan assets is allocated to us as of December 31, 2013. The amount of Dynegy postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2013 was $1 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2013:

(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	1	$	—	$	—	$	1
Equity securities:
U.S. large capitalization	33		—		—		33
International	8		—		—		8
Debt securities:
U.S. treasury and agency securities	13		1		—		14
Municipal bonds	—		5		—		5
Corporate bonds	—		6		—		6
Total	$	55	$	12	$	—	$	67

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As described above, a portion of Ameren’s postretirement plan assets was allocated to us as of December 31, 2012. The amount of Ameren postretirement plan assets allocated to us for financial reporting purposes as of December 31, 2012 was $21 million based on the number of our non-EEI employees. The following table sets forth, by level within the fair value hierarchy discussed in Note 9—Fair Value Measurements, the EEI postretirement benefit plans assets measured at fair value as of December 31, 2012:

(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	—	$	1	$	—	$	1
Equity securities:
U.S. large capitalization	32		—		—		32
International	7		—		—		7
Debt securities:
U.S. treasury and agency securities	—		11		—		11
Municipal bonds	—		5		—		5
Corporate bonds	—		6		—		6
Total	$	39	$	23	$	—	$	62

Net Periodic Benefit Cost

The following table presents the components of our net periodic benefit cost of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Ameren’s and Dynegy’s pension and postretirement benefit plans during 2013, 2012 and 2011:

(amounts in millions)	Pension Benefits			Postretirement Benefits
2013
Service cost	$	5		$	2
Interest cost	10			3
Expected return on plan assets	(13		)	(5		)
Amortization of:
Prior service cost	(1		)	(8		)
Actuarial loss	6			5
Settlements	1			—
Curtailment gain (a)	—			(26		)
Net periodic benefit cost	$	8		$	(29	)
2012
Service cost	$	5		$	3
Interest cost	10			6
Expected return on plan assets	(13		)	(6		)
Amortization of:
Prior service cost	(1		)	(3		)
Actuarial loss	6			4
Curtailment loss (b)	2			—
Net periodic benefit cost	$	9		$	4
2011
Service cost	$	6		$	3
Interest cost	11			6
Expected return on plan assets	(13		)	(6		)
Amortization of:
Prior service cost	—			(3		)
Actuarial loss	3			2
Net periodic benefit cost	$	7		$	2

47

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

_________________________________________

(a) Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.

(b) Represents EEI’s pension and management postretirement benefit plans’ curtailment loss recognized as a result of its 2012 employee reduction program.

In addition to the above net periodic benefit cost for pension benefits, we were allocated $1 million, $2 million and $1 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively. We were also allocated less than $1 million, $1 million and $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively.

The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2014 are as follows:

(amounts in millions)	Pension Benefits (a)		Postretirement Benefits (a)
Prior service cost (credit)	$	—	$	(4	)
Net actuarial loss	1		3
Total	$	1	$	(1	)

_________________________________________

(a) Includes only amounts for EEI’s plans.

The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Plan.

The expected pension and postretirement benefit payments for expected future service, as of December 31, 2013, are as follows:

(amounts in millions)	Pension Benefits (a)		Postretirement Benefits (a)
2014	$	14	$	3
2015	$	6	$	3
2016	$	7	$	3
2017	$	7	$	3
2018	$	7	$	3
2019 - 2023	$	32	$	14

_________________________________________

(a) Includes only amounts for EEI’s plans.

The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2013, 2012 and 2011:

	Pension Benefits						Postretirement Benefits
	2013		2012		2011		2013		2012		2011
Discount rate (a)	(b)		4.36	%	5.33	%	(c)		4.29	%	5.39	%
Expected return on plan assets (a)	7.65	%	7.84	%	8.00	%	7.59	%	7.87	%	7.93	%
Increase in future compensation (a)	(d)		3.70	%	3.70	%	(e)		3.86	%	3.83	%
Ameren - Medical cost trend rate (initial)	N/A		N/A		N/A		5.00	%	5.50	%	6.00	%
Ameren - Medical cost trend rate (ultimate)	N/A		N/A		N/A		5.00	%	5.00	%	5.00	%
Ameren - Years to ultimate rate	N/A		N/A		N/A		0		1 year		2 years
EEI - Medical cost trend rate (initial)	N/A		N/A		N/A		(f)		8.30	%	8.65	%
EEI - Medical cost trend rate (ultimate)	N/A		N/A		N/A		4.50	%	4.50	%	4.50	%
EEI - Years to ultimate rate	N/A		N/A		N/A		(g)		15 years		16 years

_________________________________________

(a) A weighted average rate of EEI’s and Ameren’s pension and postretirement plans.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(b) The discount rate used for EEI’s pension plan was 4.00% and 4.67% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s pension plans was 4.00% for the period from January 1, 2013 through December 1, 2013.

(c) The discount rate used for EEI’s postretirement plans was 4.00% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00% for EEI union employees and 4.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s postretirement plans was 4.00% for the period from January 1, 2013 through December 1, 2013.

(d) The average rate of compensation increase used for EEI’s pension plan was 5.97% and 3.50% for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s pension plans was 3.50% for the period from January 1, 2013 through December 1, 2013.

(e) The average rate of compensation increase used for EEI’s postretirement plans was 6.35% for EEI union employees and 3.81% for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35% for EEI union employees and 3.50% for EEI management employees and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s postretirement plans was 3.50% for the period from January 1, 2013 through December 1, 2013.

(f) The initial medical cost trend rate used for EEI’s postretirement plans was 7.96% for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96% for EEI union employees and 7.75% for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.

(g) The years to ultimate trend rate used for EEI’s postretirement plans was 14 years for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 14 years for EEI union employees and 10 years for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.

The table below reflects the sensitivity to potential changes in key assumptions:

	Pension Benefits (a)		Postretirement Benefits (a)
(amounts in millions)	Service Cost and Interest Cost	Projected Benefit Obligation	Service Cost and Interest Cost		Postretirement Benefit Obligation
1.00% increase in annual medical trend	N/A	N/A	$	1	$	5
1.00% decrease in annual medical trend	N/A	N/A	$	—	$	(4	)

_________________________________________

(a) Includes amounts for EEI’s plans and our participation in Dynegy’s plans.

Other

Ameren sponsored a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees, including our employees, prior to December 2, 2013, the date of the AER Acquisition. Effective December 2, 2013, our employees, excluding the EEI employees, participate in the Dynegy Inc. 401(k) Plan. Prior to December 31, 2013, the EEI Bargaining Unit 401(k) Plan covered all eligible EEI union employees and the EEI Management 401(k) Plan covered all eligible EEI management employees. Effective January 1, 2014, these plan benefits were frozen. Contributions stopped as of that date and EEI participants became eligible to participate in the Dynegy Inc. 401(k) Plan. These 401(k) plans allowed employees to contribute a portion of their compensation in accordance with specific guidelines. The plan sponsor matched a percentage of the employee contributions up to certain limits. Our portion of the matching contribution to the Ameren 401(k) plan was $1 million, $1 million and $2 million for the period from January 1 through December 1, 2013 and the years ended December 31, 2012 and 2011, respectively. The matching contribution to the EEI 401(k) plans was $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

49

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7—INCOME TAXES

Our loss before income taxes was $254 million and $69 million for the year ended December 31, 2013 and 2012, respectively. Our income before income taxes was $77 million for the year ended December 31, 2011. The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate:

	Year Ended December 31,
(amounts in millions)	2013		2012		2011
Statutory federal income tax rate:	35	%	35	%	35	%
Increases (decreases) from:
Tax credits	—		(2	)	(1	)
Amortization of investment tax credit	—		—		(1	)
State tax	6		7		6
Production activities deduction	—		—		3
Reserve for uncertain tax positions	—		2		—
Acquisition adjustment (a)	(15	)	—		—
Effective income tax rate	26	%	42	%	42	%

_________________________________________

(a) Acquisition adjustment is primarily the result of the loss of expected benefits from the NOL carryforward in existence at the Acquisition Date due to IRC Section 382 limits.

The following table presents the components of income tax expense (benefit):

	Year Ended December 31,
(amounts in millions)	2013			2012			2011
Current taxes:
Federal	$	(50	)	$	(15	)	$	(21	)
State	(14		)	(5		)	(7		)
Deferred taxes:
Federal	6			(6		)	43
State	(6		)	(2		)	18
Deferred investment tax credits, amortization	(1		)	(1		)	(1		)
Total income tax expense (benefit)	$	(65	)	$	(29	)	$	32

The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois increased current income tax expense in 2011 by $3 million.

The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences:

	December 31,
(amounts in millions)	2013			2012
Accumulated deferred income taxes, net liability (asset):
Plant related	$	541		$	424
Deferred employee benefit costs	(24		)	(37		)
ARO	(16		)	(28		)
Other (a)	38			(36		)
Total net accumulated deferred income tax liabilities (b)	$	539		$	323

_________________________________________

50

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(a) Included deferred tax assets related to net operating loss and tax credit carryforwards as of December 31, 2012.

(b) Includes $11 million in “Other current assets” on the balance sheet as of December 31, 2012.

Uncertain Tax Positions

A reconciliation of the change in the unrecognized tax benefit balance is as follows:

	Year Ended December 31,
(amounts in millions)	2013			2012			2011
Unrecognized tax benefits - beginning of year	$	6		$	9		$	20
Increases based on tax positions prior to current year	2			1			1
Decreases based on tax positions prior to current year	(3		)	(2		)	(12		)
Increases based on tax positions related to current year	—			—			1
Decreases based on tax positions related to current year	(1		)	(1		)	—
Adjustment of balance due to change in ownership	(3		)	—			—
Decreases related to the lapse of statute of limitations	(1		)	(1		)	(1		)
Unrecognized tax benefits - end of year	$	—		$	6		$	9
Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates	$	—		$	—		$	1

Interest charges (income) and penalties accrued on tax liabilities on a pretax basis are recognized as interest charges (income) or miscellaneous expense, respectively, in the statements of income (loss).

A reconciliation of the change in the liability for interest on unrecognized tax benefits is as follows:

	Year Ended December 31,
(amounts in millions)	2013			2012		2011
Liability for interest - beginning of year	$	1		$	1	$	2
Interest charges (income)	—			—		(1		)
Adjustment of balance due to change in ownership	(1		)	—		—
Liability for interest - end of year	$	—		$	1	$	1

As of December 31, 2013, 2012 and 2011, we accrued no amount for penalties with respect to unrecognized tax benefits.

Upon the AER Acquisition, we are included in the consolidated tax returns of Dynegy. Under U.S. federal income tax law, Dynegy files consolidated income tax returns for itself and its subsidiaries. Dynegy is responsible for the federal tax liabilities of its subsidiaries, which include the income and business activities of the ring-fenced entities and Dynegy’s other affiliates.  Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized was similar to that which would have been owed had we been separately subject to tax. Genco and Dynegy have entered into a new tax sharing agreement that also provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement.  As of December 31, 2013 we owed approximately $1 million to Dynegy pursuant to the new tax sharing agreement.

Upon the AER Acquisition, we experienced an “ownership change,” as defined under IRC Section 382 and Ameren recognized a worthless stock loss on the basis of its stock in the Company. As a result of both the ownership change and the worthless stock loss, the Company reduced its NOLs to zero and reduced other tax basis of assets by $433 million. The total amount of NOLs that could be used in any one year following such ownership change was limited such that all of our NOLs cannot be used against future taxable income. The adjustments to the NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $178 million and a reduction to our income tax benefit for 2013 in the amount of $39 million.

In 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a reduction in our uncertain tax liabilities of $4 million.

Genco is currently under federal audit for the periods 2007 through 2011. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to

51

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

examination by various states for a period of up to one year after formal notification to the states. As a result of the AER Acquisition, we are indemnified by Ameren for any federal or state tax adjustment for tax periods prior to December 2, 2013.

NOTE 8—DERIVATIVE FINANCIAL INSTRUMENTS

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our treasury team manages our financial risks and exposures associated with interest expense variability.

Our commodity risk management strategy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to three-year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.

We manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, Reliability Must Run contracts, fixed price coal purchases and other arrangements that do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale.” As a result, the gains and losses with respect to these arrangements are not reflected in the consolidated statements of operations until the delivery occurs.

We did not have a material amount of outstanding derivative positions as of December 31, 2013. The following table presents open gross derivative commodity contract volumes by commodity type as of December 31, 2013 and 2012:

	Quantity (in millions)
Commodity	2013	2012
Coal (in tons)	—	5
Fuel oils (in gallons) (a)	—	40
Natural gas (in mmbtu) (b)	—	42
Power (in MWh)	—	—

________________________________________

(a) Fuel oils consist of heating and crude oil.

(b) Amounts include commodity contracts classified as held for sale.

Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. Please read Note 9—Fair Value Measurements for further discussion of our methods of assessing the fair value of derivative instruments. For our physical contracts that qualify for the NPNS exception to derivative accounting rules, the revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we historically reviewed the contract to determine if it qualifies for hedge accounting. In 2013, we discontinued the use of cash flow hedge accounting. Contracts that previously qualified for cash flow hedge accounting were recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurred, to the extent the hedge was effective. To the extent the hedge was ineffective, the related changes in fair value were charged or credited to operating income (loss) in the period in which the change occurred. When the contract is settled or delivered, the net gain or loss is recorded to operating income (loss).

Certain derivative contracts were entered into on a regular basis as part of our risk management program but did not qualify for, or we did not choose to elect, the NPNS exception or hedge accounting. Such contracts were recorded at fair value, with changes in fair value charged or credited to the statements of operations in the period in which the change occurred.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We did not elect to adopt this guidance for any eligible commodity contracts.

52

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We did not have any derivative instruments as of December 31, 2013. The following table presents the carrying value of all derivative instruments as reported in our balance sheets as of December 31, 2012:

(amounts in millions)		Year Ended December 31, 2012
Derivative assets not designated as hedging instruments
Commodity contracts:
Coal	Other assets	$	1
Fuel oils	Other current assets	2
	Other assets	1
Natural gas	Other current assets	4
	Total assets	$	8
Derivative liabilities not designated as hedging instruments
Commodity contracts:
Coal	Other current liabilities	$	7
	Other deferred credits and liabilities	3
Fuel oils	Other current liabilities	1
	Other deferred credits and liabilities	1
Natural gas	Liabilities held for sale	3
	Total liabilities	$	15

The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated OCI was $6 million and $7 million, respectively, as of December 31, 2013 and 2012. These interest rate swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. Over the next 12 months, less than $1 million of the loss will be amortized.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

53

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of five groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of December 31, 2012, if counterparty groups were to fail completely to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

(amounts in millions)	Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Oil and Gas Companies		Total
2012 (a)	$	2	$	1	$	—	$	2	$	2	$	7

________________________________________

(a) Includes amounts classified as held for sale.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. As of December 31, 2013, we held no collateral to reduce exposure. As of December 31, 2012, we held other collateral which consisted of letters of credit in the amount of $1 million to reduce exposure. The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012:

(amounts in millions)	Coal Producers		Commodity Marketing Companies		Electric Utilities		Financial Companies		Oil and Gas Companies		Total
2012 (a)	$	1	$	—	$	—	$	1	$	—	$	2

________________________________________

(a) Includes amounts classified as held for sale.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to our credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2013, and (2) those counterparties with rights to do so requested collateral:

(amounts in millions)	Aggregate Fair Value of Derivative Liabilities (a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required
2012 (b)	$	48	$	—	$	31

__________________________________________

(a) Prior to consideration of master trading and netting agreements and including accrual and NPNS contract exposures.

(b) Includes amounts classified as held for sale.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges

The following table presents the pretax net gain or loss for the years ended December 31, 2013 and 2012, associated with derivative instruments designated as cash flow hedges:

(amounts in millions)	Gain (Loss) Recognized in OCI (a)		Location of (Gain) Loss Reclassified from Accumulated OCI into Income (b)	(Gain) Loss Reclassified from Accumulated OCI into Income (b)		Location of Gain (Loss) Recognized in Income (c)	Gain (Loss) Recognized in Income (c)
2013
Interest rate (d)	$	—	Interest Charges	$	1	Interest Charges	$	—
2012
Interest rate (d)	$	—	Interest Charges	$	1	Interest Charges	$	—

__________________________________________

(a) Effective portion of gain (loss).

(b) Effective portion of (gain) loss on settlements.

(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

Other Derivatives

The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2013 and 2012:

	Location of Gain (Loss) Recognized in Income	Gain (Loss) Recognized in Income
(amounts in millions)		2013			2012
Coal	Operating Expenses - Fuel	$	9		$	(9	)
Fuel oils	Operating Expenses - Fuel	(1		)	(9		)
Natural gas (generation) (a)	Operating Expenses - Fuel	(1		)	—
Power	Operating Revenues	—			—
	Total	$	7		$	(18	)

________________________________________

(a) Includes amounts classified as held for sale.

NOTE 9—FAIR VALUE MEASUREMENTS

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain over-the-counter derivative instruments, including natural gas swaps. Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside

55

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

We did not have any significant financial assets and liabilities classified as Level 3 in the fair value hierarchy at December 31, 2013. In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings.

We did not have a material amount of outstanding derivative positions as of December 31, 2013. The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:

		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
	Derivative assets - commodity contracts (a):
	Coal	$	1	$	—	$	—	$	1
	Fuel oils	2		—		1		3
	Natural gas	4		—		—		4
	Total assets	$	7	$	—	$	1	$	8
Liabilities:
	Derivative liabilities - commodity contracts (a):
	Coal	$	10	$	—	$	—	$	10
	Fuel oils	2		—		—		2
	Natural gas	3		—		—		3
	Total liabilities	$	15	$	—	$	—	$	15

_________________________________________

(a) The derivative asset and liability balances are presented net of counterparty credit considerations.

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The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Year Ended December 31,
(amounts in millions)	2013			2012
Fuel oils:
Beginning balance at January 1	$	1		$	1
Realized and unrealized gains (losses):
Included in earnings	—			—
Total realized and unrealized gains (losses)	—			—
Purchases	—			—
Settlements	(1		)	—
Transfers into Level 3	—			1
Transfers out of Level 3	—			(1		)
Ending balance at December 31	$	—		$	1
Change in unrealized gains (losses) related to assets/liabilities held at December 31	$	—		$	—

Transfers into or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Fuel oils transfers between Level 1 and Level 3 were primarily caused by changes in availability of financial trades observable on electronic exchanges from the previous reporting period for the year ended December 31, 2012. Any reclassifications are reported as transfers into or out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 2013 and 2012, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts.

Please read Note 6—Retirement Benefits for further discussion regarding our participation in Dynegy’s and EEI’s pension and postretirement benefit plans.

Our carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. The estimated fair value of long-term debt is based on the quoted market prices for same or similar issuances for companies with similar credit profiles, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt:

	December 31, 2013				December 31, 2012
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including current portion)	$	824	$	683	$	824	$	618

NOTE 10—COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. Material legal and administrative proceedings include the following:

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New Source Review and Clean Air Litigation. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the CAA when the plants implemented modifications. The EPA's initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

Coffeen, Newton and Joppa Facilities.Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the CAA seeking detailed operating and maintenance history data with respect to our Coffeen, Newton and Joppa facilities. In August 2012, the EPA issued a Notice of Violation alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated PSD, Title V permitting and other requirements. We believe our defenses to the allegations described in the Notice of Violation are meritorious. A recent decision by the United States Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned, this decision may provide an additional defense to the allegations in the Newton facility Notice of Violation.

Ultimate resolution of these matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Variance.In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting IPH a variance extending the applicable compliance dates for MPS SO₂ emission limits. We believe the petition for review is without merit and on January 17, 2014, IPH filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted the motion and dismissed the appeal.

Newton and Coffeen Facilities’ Groundwater. Hydrogeologic investigations of the CCR surface impoundments have been performed at the Newton and Coffeen facilities.  Groundwater monitoring results indicate that the CCR surface impoundments at each of the facilities potentially impact onsite groundwater. 

In 2012, the Illinois Environmental Protection Agency (“Illinois EPA”) issued violation notices with respect to groundwater conditions at the Newton and Coffeen facilities’ ash pond systems. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. 

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. The ongoing operation of existing or new electric generation and transmission facilities, involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to our coal-fired facilities, the EPA is developing environmental regulations that will have a significant impact on the electricity generators. These regulations could be particularly burdensome for certain companies, including ours, that operate coal-fired facilities. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of GHG emissions from new facilities; revised NAAQS for SO₂, NO_x and fine particulates; the CSAPR, which would have required further reductions of SO₂ and NO_x emissions from facilities; a regulation that governs management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, metals, and acid gases from facilities; revised NSPS for particulate matter, SO₂, and NO_x emissions from new sources; new standards for cooling water intake structures at facilities; and new effluent standards applicable to discharges from steam-electric generating units. The EPA is expected to propose CO₂ limits for existing fossil-fuel fired electric generation units in 2014. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our facilities, which could have an adverse effect on our results of operations, financial position, and liquidity, including

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the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

We expect to incur capital costs of $45 million in 2014 to comply with existing environmental regulations, including the CAIR, the MPS and the final MATS rule. In addition, these estimated costs assume that CCR will continue to be regarded as nonhazardous. The estimate does not include the EPA’s proposed CCR regulations, the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013, as the technology and compliance requirements ultimately to be selected in these final rules are not yet known. The estimate could change significantly depending upon a variety of factors including:

• additional or modified federal, state or local requirements;

• further regulation of GHG emissions;

• revisions to CAIR or reinstatement of CSAPR;

• delays or accelerations of rulemaking and implementation by the EPA or state agencies;

• new NAAQS, new standards intended to achieve NAAQS or changes to existing standards for ozone, fine particulates, SO₂, and NO_x emissions;

• additional rules governing air pollutant transport;

• regulations or requirements under the Clean Water Act regarding cooling water intake structures or effluent standards;

• finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;

• new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;

• new technology;

• variations in costs of material or labor; and

• alternative compliance strategies or investment decisions.

The following sections describe the more significant environmental rules that affect or could affect our operations:

Clean Air Act

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the CAIR). The CAIR required generating facilities in 28 states, including Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions.

In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR was to become effective on January 1, 2012, for SO₂ and annual NO_x reductions and on May 1, 2012, for ozone season NO_x reductions, with further reductions in 2014. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR and, in August 2012, the court vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In March 2013, the EPA and certain environmental groups filed an appeal of the Court of Appeals’ remand of the CSAPR to the United States Supreme Court. The United States Supreme Court has agreed to consider the appeal and is expected to issue a ruling on the appeal during its current term, which ends in June 2014. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the CSAPR is reinstated following completion of judicial review.

In December 2011, the EPA issued the MATS, which establish emission limits for mercury and other hazardous air pollutants, such as acid gases and metals, equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards establish limits for hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems or quarterly emission testing for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission limits. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

Separately, in December 2012, the EPA issued a final rule that made the NAAQS for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to facilities but could require reductions in SO₂ and NO_x emissions. Compliance with the final rule is required by 2020, unless an extension of time to achieve compliance is granted. We

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continue to evaluate the new standard while the state of Illinois develops its attainment plans.

In September 2011, the EPA announced that it was implementing the 2008 NAAQS for ozone. The state of Illinois will be required to develop an attainment plan to comply with the 2008 NAAQS for ozone, which could result in additional emission control requirements for power plants by 2020. The EPA also is in the process of completing its ongoing five-year review of the current ozone NAAQS, which may result in a more stringent standard. Rulemaking action concerning the ozone NAAQS is not anticipated until 2015. We continue to assess the impacts of ozone NAAQS developments.

In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois, as nonattainment for the one-hour SO₂ NAAQS based on existing ambient monitoring data. The designations became effective in October 2013, and the states must develop plans within 18 months to reduce emissions so that they can achieve the ambient air quality standard within five years. None of our facilities are located in areas that were initially designated nonattainment by the EPA. The EPA expects to complete SO₂ nonattainment area designations by 2018 for areas that currently lack sufficient monitoring data. We continue to assess the impacts of these SO₂ NAAQS developments.

In September 2012, the IPCB granted AER a variance to extend the applicable compliance dates for MPS SO₂ emission limits through December 31, 2019, subject to certain conditions described below. The variance provides additional time for economic recovery and related power price improvements necessary to support the installation of flue gas desulfurization (i.e. scrubber) systems at the Newton facility such that the AER coal-fired fleet in Illinois can meet the MPS system-wide SO₂ limit. The IPCB approved AER's proposed plan to restrict its SO₂ emissions through 2014 to levels lower than those required by the MPS to offset any environmental impact from the variance. The IPCB’s order also included a schedule of milestones for completion of various aspects of the installation of the Newton scrubber systems. The first milestone relates to the completion of engineering design by July 2015, while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.

In May 2013, IPH and AER filed a request with the IPCB to transfer the September 2012 variance to IPH. The IPCB denied the request on procedural grounds but indicated that IPH could file its own request for variance relief. In July 2013, IPH, along with certain co-petitioners, filed such a petition for variance relief. In November 2013, the IPCB approved the variance petition. The November 2013 variance includes the same project milestones for the completion of the Newton scrubber project as the September 2012 variance and also requires, as was proposed by IPH, additional environmental protections in the form of enforceable commitments to cap the IPH system’s SO₂ emissions over the period from the fourth quarter 2013 through December 31, 2020, retire IPRG’s Edwards Unit 1 as soon as permitted by the MISO, and, during the variance period, use only low sulfur coal at the Newton, Joppa and Edwards facilities and optimize operation of the existing scrubbers at our Coffeen facility and IPRG’s Duck Creek facility.

In January 2014, an environmental group filed a petition in the Illinois Fourth District Appellate Court seeking review of the IPCB’s November 2013 decision and order granting the variance relief. We believed the petition for review was without merit and on January 17, 2014, IPH filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted the motion and dismissed the appeal.

To comply with the MPS and other air emissions laws and regulations, we have installed or are installing equipment designed to reduce emissions of mercury, NO_x, and SO₂. We have installed two scrubbers at the Coffeen facility. Two additional scrubbers are being constructed at the Newton facility. We will continue to review and adjust our compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.

Environmental compliance costs could be prohibitive at some of our facilities as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NO_x budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program’s allowances for SO₂ emissions and created annual and ozone season NO_x allowances. We expect to have adequate CAIR allowances for 2014 to avoid needing to make external purchases to comply with these programs.

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GHG Regulation

State and federal authorities, including the United States Congress, have considered initiatives to limit GHG emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. Our emissions of GHG vary among our facilities, but coal-fired power plants are significant sources of CO₂.

In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that GHG emissions, including CO₂, endanger human health and welfare and that emissions of GHG from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that GHG emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of GHG in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of GHG, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating GHG emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have GHG-specific provisions added to its permits upon renewal. Currently, Genco facilities have operating permits that, when renewed, may be modified to address GHG emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of GHG over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control GHG emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their GHG emissions exceed the applicable emissions threshold. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule. In October 2013, the United States Supreme Court granted the petition agreeing to consider whether the Clean Air Act authorizes the EPA to regulate emissions of GHG from stationary sources, including power plants, as a result of the EPA’s determination to regulate GHG emissions from motor vehicles. A ruling is expected in 2014.

In June 2013, the Obama Administration announced that it had directed the EPA to set CO₂ emissions standards for both new and existing power plants. The EPA proposed revised CO₂ emissions regulations for new electricity generating units in September 2013. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. This proposed NSPS for CO₂ emissions would apply only to new fossil-fuel fired electric facilities and therefore does not affect any of our existing facilities. A final rule is expected in 2014. In addition, the Obama Administration directed the EPA to propose a CO₂ emissions standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, we are unable to predict the outcome or impacts of such future regulations.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO₂ emissions from several industrial companies, including our facilities, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. In May 2013, the dismissal of the lawsuit was affirmed by the United States Court of Appeals for the Fifth Circuit. The plaintiffs did not seek review by the United States Supreme Court.

Future federal and state legislation or regulations that mandate limits on the emission of GHG would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. These compliance costs could be prohibitive at some of our facilities as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets. As a result, mandatory limits could have a material adverse impact on our results of operations, financial position and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to our Coffeen, Newton, and Joppa

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facilities. In August 2012, we received a Notice of Violation from the EPA alleging violations of permitting requirements at our Newton facility, including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006 and 2007 at our Newton facility violated federal law. We believe our defenses to the allegations described in the Notice of Violation are meritorious. A recent decision by the United States Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned, this decision may provide an additional defense to the allegations in the Newton facility Notice of Violation. We are unable to predict the outcome of this matter.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule would also require existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system.  The final rule is scheduled to be issued in 2014, with compliance expected within eight years thereafter. Our facilities with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. We are currently evaluating the proposed rule, and our assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have a material adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our facilities.

In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revisions target wastewater streams associated with flue gas desulfurization (i.e., scrubbers), fly ash, bottom ash, flue gas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning, and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If adopted as proposed, we would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations. The EPA expects to issue a final rule in 2014. The proposed rule, if adopted, may cause us to incur significant costs.

Ash Management

There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our facilities. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. The EPA is expected to issue a final CCR rule in late 2014. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. We are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. We are also evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

The Illinois EPA has issued violation notices with respect to groundwater conditions existing at our Coffeen and Newton ash pond systems. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. In April 2013, AER filed a proposed rulemaking

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with the IPCB which, if approved, would provide for the systematic and eventual closure of AER’s ash ponds. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, preventative response, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The AER rulemaking has been stayed to allow the Illinois EPA proposed rulemaking to proceed. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our results of operations, financial position, and liquidity. During the first quarter 2013, we revised our ARO fair value estimates relating to ash ponds. Please read Note 1—Summary of Significant Accounting Policies for further discussion related to our AROs.

Guaranty

Guaranty Agreement.In connection with the AER Acquisition, Genco has provided a Guaranty Agreement of certain obligations of IPH up to $25 million. Concurrently with the closing of the Transaction Agreement on December 2, 2013, Genco entered into the Guaranty Agreement, capped at $25 million in favor of Ameren, pursuant to which Genco guaranteed for a period of two years after the closing (subject to certain exceptions), up to $25 million with respect to IPH’s indemnification obligations and certain reimbursement obligations under the Transaction Agreement.

Other Commitments

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, plant sites and power generation assets. The following describes the more significant commitments outstanding at December 31, 2013:

Coal Commitments. At December 31, 2013, we had contracts in place to supply coal to our generation facilities with minimum commitments of $366 million through 2017.

Coal Transportation.At December 31, 2013, we had coal transportation contracts in place through 2023 and rail car leases in place through 2026 with aggregate minimum commitments of $279 million.

Operating Leases.Our operating leases include minimum lease payment obligations of less than $1 million per year through 2018 associated with office leases.

Total rental expense included in operating expenses, for the years ended December 31, 2013, 2012 and 2011 was $4 million, $4 million and $2 million, respectively.    

Other Obligations.  Our other obligations included severance and retention obligations of $3 million in connection with a reduction in workforce and $4 million over the next 26 years under a facilities service agreement to compensate an affiliated entity for additions made on our electric generating facilities.

NOTE 11—IMPAIRMENT AND OTHER CHARGES

The following table summarizes the pretax charges recognized for the years ended December 31, 2013, 2012 and 2011:

(amounts in millions)	Long-Lived Assets and Related Charges		Emission Allowances		Total
2013	$	199	$	—	$	199
2012	$	70	$	—	$	70
2011	$	34	$	1	$	35

Each of the above charges was recorded in the statements of operations as “Impairment and other charges.” The impairment charges did not result in a violation of our debt covenants or counterparty agreements. Each of the charges is discussed below.

Long-lived Assets

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds

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the undiscounted cash flows, we would recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.

We recorded impairment charges on our long-lived assets for the years ended December 31, 2011 and 2012, under a held and used model. We recorded additional impairment charges in 2013 under the held for sale model.

Key assumptions used in the determination of estimated undiscounted cash flows of our long-lived assets tested for impairment under a held and used model included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. These assumptions are subject to a high degree of judgment and complexity. In comparison, impairment analysis under the held for sale model involves only comparison of the carrying cost of the asset group to the asset group’s estimated fair value less cost to sell and recording an impairment charge for any excess of that carrying value over the estimated fair value less cost to sell. We assess impairment at the lowest level of identifiable cash flows.

We recorded a pretax charge to earnings of $199 million for the year ended December 31, 2013, to reflect the impairment of the Gas-Fired Facilities under a held for sale model. Fair value was based on the actual sales price of $138 million realized upon sale of the Gas-Fired Facilities to Medina Valley in October 2013. The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower Gas-Fired Facilities as the Elgin facility was previously impaired (pretax charge to earnings of $70 million) under held and used accounting guidance during the fourth quarter of 2012. We also recorded an $82 million income tax benefit as a result of the 2013 impairment charge. In December 2011, we ceased operations of our Meredosia and Hutsonville facilities. As a result, we recorded a noncash pretax asset impairment charge of $26 million to reduce the carrying value of the Meredosia and Hutsonville facilities to their estimated fair values, a $4 million impairment of materials and supplies and $4 million for severance costs.

We will continue to monitor the market price for power and the related impact on electric margin, our liquidity needs, and other events or changes in circumstances that indicate that the carrying value of our facilities may not be recoverable as compared to their undiscounted cash flows. We could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted future cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside our control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of our facilities, and also as a result of factors that may be within our control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell our facilities. As of December 31, 2013, the carrying value of long-lived assets exceeded their realizable fair value by an amount in excess of $1 billion.

Intangible Assets

In July 2011, the EPA issued the CSAPR, which created new allowances for SO₂ and NO_x emissions, and restricted the use of preexisting SO₂ and NO_x allowances to the acid rain program and to the NO_x budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, we recorded a $1 million non-cash pretax impairment charge relating to emission allowances.

The fair value of the SO₂ and NO_x emission allowances was based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.

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NOTE 12—ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows:

(amounts in millions)	Year Ended December 31, 2013			Year Ended December 31, 2012
Beginning of period	$	(40	)	$	(72	)
Current period other comprehensive income:
Actuarial gain and plan amendments (net of tax expense of $8 and $20, respectively)	12			28
Amounts reclassified from accumulated other comprehensive income (loss):
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net (net of tax benefit of zero and zero, respectively) (a)	1			1
Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax expense of $1 and $2, respectively) (b)	1			3
Amounts reclassified from accumulated other comprehensive income (loss) (net of tax benefit of $9 and zero, respectively) (c)	(13		)	—
Total amounts reclassified from accumulated other comprehensive income (loss)	(11		)	4
Net current period other comprehensive income (loss), net of tax	1			32
AER Acquisition (net of tax expense of $20 and zero, respectively) (d)	28			—
End of period	$	(11	)	$	(40	)

__________________________________________

(a) Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest Charges in our consolidated statements of operations.

(b) Amounts are associated with our defined benefit pension and other postretirement benefit plans and are included in the computation of net periodic pension cost. Please read Note 6—Retirement Benefits for further discussion.

(c) Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Other operations and maintenance in our consolidated statements of operations. Please read Note 6—Retirement Benefits for further discussion.

(d) Amount related to the transfer of certain defined benefit pension and other postretirement benefit plans as a part of the AER Acquisition. Please read Note 6—Retirement Benefits for further discussion.

SELECTED QUARTERLY INFORMATION (Unaudited) (In millions)

Quarter Ended	Operating Revenues		Operating Income (Loss) (a)			Net Income (Loss)			Net Income (Loss) Attributable to Illinois Power Generating Company
March 31, 2013	$	187	$	(204	)	$	(129	)	$	(129	)
March 31, 2012	$	194	$	13		$	(3	)	$	(1	)
June 30, 2013	$	187	$	(25	)	$	(22	)	$	(22	)
June 30, 2012	$	194	$	(4	)	$	(6	)	$	(4	)
September 30, 2013	$	275	$	—		$	(5	)	$	(5	)
September 30, 2012	$	218	$	34		$	11		$	13
December 31, 2013	$	155	$	16		$	(33	)	$	(32	)
December 31, 2012	$	202	$	(60	)	$	(42	)	$	(41	)

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_________________________________________

(a) Includes pretax “Impairment and other charges” of $199 million and $70 million recorded during the years ended December 31, 2013 and 2012, respectively. Please read Note 11—Impairment and Other Charges for further discussion.

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Genco was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2013 fiscal year.

(a) Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2013.

(b) Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of our company are being made only in accordance with authorizations of our management and directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, we used the criteria set forth in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992. Based on the results of this assessment and on those criteria, we concluded that our internal control over financial reporting was effective as of December 31, 2013.

(c) Change in Internal Control

There has been no change in internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. From October 1, 2013 to December 2, 2013, the internal controls over financial reporting were performed by Ameren personnel. After December 2, 2013, the internal controls over financial reporting were performed by Dynegy personnel.

ITEM 9B.    OTHER INFORMATION

Not Applicable

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

This item is omitted in reliance on General Instruction (I)(2)(C) of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

This item is omitted in reliance on General Instruction (I)(2)(C) of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

This item is omitted in reliance on General Instruction (I)(2)(C) of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

This item is omitted in reliance on General Instruction (I)(2)(C) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

We paid audit fees of $650,000, and zero audit related, tax and other fees to PricewaterhouseCooopers LLP, our principal independent registered public accounting firm, during the year ended December 31, 2013. All of the fees for the year ended December 31, 2013 were approved by our Board of Directors.  For the year ended December 31, 2012, all fees are included in Ameren’s definitive proxy statement for the 2013 annual meeting of shareholders. 

PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements	Page No.
Report of Independent Registered Public Accounting Firm	27
Consolidated Balance Sheets - December 31, 2013 and 2012	28
Consolidated Statements of Operations - Years Ended December 31, 2013, 2012 and 2011	29
Consolidated Statements of Comprehensive Income (Loss) - Years Ended December 31, 2013, 2012 and 2011	30
Consolidated Statements of Cash Flows - Years Ended December 31, 2013, 2012 and 2011	31
Consolidated Statements of Changes in Stockholder’s Equity - Years Ended December 31, 2013, 2012 and 2011	32
(a)(2) Financial Statement Schedules not required

(a)(3) Exhibits

Reference is made to the Exhibit Index commencing on page 70.

(b) Exhibits

Exhibits are listed in the Exhibit Index commencing on page 70.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ILLINOIS POWER GENERATING COMPANY (registrant)
Date:	March 28, 2014	By	/s/ ROBERT C. FLEXON
			Robert C. Flexon
			President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ ROBERT C. FLEXON	President and Chief Executive Officer  (Principal Executive Officer)	March 28, 2014
Robert C. Flexon
/s/ CLINT C. FREELAND	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 28, 2014
Clint C. Freeland
/s/ J. CLINTON WALDEN	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 28, 2014
J. Clinton Walden
/s/ KEVIN HOWELL	Chairman	March 28, 2014
Kevin Howell
/s/ MARIO ALONSO	Director	March 28, 2014
Mario Alonso
/s/ MARJORIE BOWEN	Director	March 28, 2014
Marjorie Bowen
/s/ CAROLYN J. BURKE	Director	March 28, 2014
Carolyn J. Burke
/s/ JULIUS COX	Director	March 28, 2014
Julius Cox

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EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the registrant and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith: 

Exhibit Number	Description	Previously filed as Exhibit to:
2.1	Transaction Agreement, dated as of March 14, 2013, between Ameren and Illinois Power Holdings, LLC	(incorporated by reference to Exhibit 2.1, Form 8-K of Dynegy Inc. filed on March 15, 2013, File No. 001-33443)
2.2	Asset Purchase Agreement, dated as of March 14, 2013, by and between Medina Valley and Genco LLC	(incorporated by reference to Exhibit 2.2, Form 8-K filed on March 14, 2013, File No. 1-14756)
2.3	Letter Agreement, dated as of December 2, 2013, amending the Transaction Agreement dated as of March 14, 2013	(incorporated by reference to Exhibit 2.2, Form 8-K of Dynegy Inc. filed on December 4, 2013, File No. 001-33443)
3.1	Articles of Incorporation of Genco	(incorporated by reference to Exhibit 3.1, Form S-4, File No. 333-56594)
3.2	Amendment to Articles of Incorporation of Genco filed April 19, 2000	(incorporated by reference to Exhibit 3.2, Form S-4, File No. 333-56594)
**3.3	Amendment to Articles of Incorporation of Genco, filed on December 2, 2013
**3.4	Amended and Restated Bylaws of Genco as amended December 2, 2013
4.1	Indenture dated as of November 1, 2000, from Genco to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture)	(incorporated by reference to Exhibit 4.1, Form S-4 File No. 333-56594)
4.2	Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to Genco's 7.95% Senior Notes, Series E due 2032	(incorporated by reference to Exhibit 4.1 Form 10-Q, filed on June 30, 2002, File No. 333-56594)
4.3	Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to Genco 7.95% Senior Notes, Series F due 2032	(incorporated by reference to Exhibit 4.5 to the 2002 Annual Report on Form 10-K, File No. 333-56594)
4.4	Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series G due 2018	(incorporated by reference to Exhibit 4.2 to the Form 8-K, filed April 9, 2008, File No. 333-56594)
4.5	Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series H due 2018	(incorporated by reference to Exhibit No. 4.55, Form S-3 File No. 333-56594)
4.6	Seventh Supplemental Indenture, dated as of November 1, 2009, to Genco Indenture, relating to Genco 6.30% Senior Notes, Series l due 2020	(incorporated by reference to Exhibit 4.8, Form 8-K, filed November 17, 2009, File No. 333-56594)
4.7	Registration Rights Agreement, dated June 6, 2002 among Ameren Energy Generating Company and the Initial Purchasers relating to the Ameren Energy Generating Company’s 7.95% Senior Notes, Series E due 2032	(incorporated by reference to Exhibit 4.1 to the Form 10-Q for the quarter ended June 30, 2002, File No. 333-56594)
4.8	Registration Rights Agreement, dated April 9, 2008 among Ameren Energy Generating Company and the Initial Purchasers relating to the Ameren Energy Generating Company’s 7.00% Senior Notes, Series G due 2018	(incorporated by reference to Exhibit 4.8 to the Form S-4 Filed May 19, 2008, File No. 333-56594)
10.1	Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and Genco	(incorporated by reference to Exhibit 10.3, Form 8-K, filed March 28, 2008, File No. 1-14756)
10.2	First Amendment dated January 1, 2010, to Amended and Restated Power Supply Agreement dated March 28, 2008, between Marketing Company and Genco	(incorporated by reference to Exhibit 10.2, 2009 Form 10-K, File No. 1-14756)

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10.3	Ameren Corporation System Amended and Restated Non-Regulated Subsidiary Money Pool Agreement, dated March 1, 2008	(incorporated by reference to Exhibit 10.1, March 31, 2008 Form 10-Q, File No. 1-14756)
10.4	Put Option Agreement, dated as of March 28, 2012, between Genco and AERG	(incorporated by reference to Exhibit 10.3, Form 8-K, filed March 28, 2008, File No. 1-14756)
10.5	Guaranty, dated as of March 28, 2012, made by Ameren in favor of Genco	(incorporated by reference to Exhibit 10.3, Form 8-K, filed March 28, 2008, File No. 1-14756)
10.6	Novation and Amendment of Put Option Agreement, dated as of March 14, 2013, by and among Medina Valley, AERG, Genco and Ameren	(incorporated by reference to Exhibit 10.3, Form 8-K, filed March 19, 2013, File No. 1-14756)
10.7	Guaranty, dated as of December 2, 2013, by Genco in favor of Ameren Corporation	(incorporated by reference to Exhibit 10.1, Form 8-K, filed December 5, 2013, File No. 333-56594)
10.8	Revolving Promissory Note, dated as of December 2, 2013, by and between Dynegy Inc, as Lender, and Illinois Power Resources, LLC, as Borrower`	(incorporated by reference to Exhibit 10.1, Form 8-K of Dynegy Inc., filed December 4, 2013, File No. 001-33443)
10.9	Letter of Credit and Reimbursement Agreement, dated as of January 29, 2014, between Illinois Power Marketing Company and Union Bank, N.A.	(incorporated by reference to Exhibit 10.1, Form 8-K, filed February 4, 2014, File No. 333-56594)
10.10	Dynegy Inc. Executive Severance Pay Plan, as amended and restated effective as of January 1, 2008	(incorporated by reference to Exhibit 10.1, Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443)††
10.11	First Amendment to the Dynegy Inc. Executive Severance Pay Plan effective as of January 1, 2010	(incorporated by reference to Exhibit 10.15, Form 10-K for the Fiscal Year Ended December 31, 2009 of Dynegy Inc, File No. 1-15659)††
10.12	Second Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of September 20, 2010	(incorporated by reference to Exhibit 10.4, Form 10-Q for the Quarter Ended September 30, 2010 of Dynegy Inc, File No. 1-15659)††
10.13	Third Amendment to the Dynegy Inc. Executive Severance Pay Plan	(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2011, File No. 1-33443)††
10.14	Fourth Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of August 8, 2011	(incorporated by reference to Exhibit 10.1, Form 10-Q for the Quarter Ended September 30, 2011 of Dynegy Inc., File No. 1- 33443)††
10.15	Dynegy Inc. Executive Change in Control Severance Pay Plan effective April 3, 2008	(incorporated by reference to Exhibit 10.1, Form 8-K of Dynegy Inc. filed on April 8, 2008, File No. 001-33443)††
10.16	First Amendment to the Dynegy Inc. Executive Change In Control Severance Pay Plan, dated as of September 22, 2010	(incorporated by reference to Exhibit 10.2, Form 10-Q for the Quarter Ended September 30, 2010 of Dynegy Inc, File No. 1-15659)††
10.17	Second Amendment to the Dynegy Inc. Executive Change in Control Severance Pay Plan	(incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013 File No. 001-33443)††
10.18	Dynegy Inc. 2009 Phantom Stock Plan	(incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443)††
10.19	First Amendment to the Dynegy Inc. 2009 Phantom Stock Plan, dated as of July 8, 2011	(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc., File No. 1- 33443)††

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10.20	Dynegy Inc. Incentive Compensation Plan, as amended and restated effective May 21, 2010	(incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2010, File No. 001-33443)††
10.21	2012 Long Term Incentive Plan	(incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012, File No. 001-33443)††
10.22	Revolving Promissory Note by and between Dynegy Inc., as Lender, and Illinois Power Resources, LLC (formerly New AmerenEnergy Resources, LLC), as Borrower	(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 4, 2013 File No. 001-33443)
10.23	Guaranty by Ameren Energy Generating Company in favor of Ameren Corporation, dated December 2, 2013	(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Illinois Power Generating Company filed on December 5, 2013 File No. 333-56594)
10.24	Letter of Credit and Reimbursement Agreement, dated as of January 29, 2014 between Illinois Power Marketing Company and Union Bank, N.A.	(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Illinois Power Generating Company filed on February 4, 2014, File No. 001-33443)
10.25	Dynegy Inc. Code of Ethics for Senior Financial Professionals, as amended on July 23, 2013	(incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K of Dynegy Inc. for the year ended December 31, 2013, File No. 001-33443)
**12.1	Ratio of Earnings to Fixed Charges
14.1	Dynegy Inc. Code of Ethics for Senior Financial Professionals, as amended on July 23, 2013	(incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K of Dynegy Inc. for the year ended December 31, 2013 File No. 1-33443
**31.1	Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**31.2	Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition Document

††Compensatory plan or arrangement.

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*Attached as Exhibit 101 to this report is the following financial information for Genco's Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011, (ii) the Consolidated Balance Sheet at December 31, 2013 and December 31, 2012, (iii) the Consolidated Statement of Cash Flows for the years ended December 31, 2013, 2012 and 2011, (iv) the Consolidated Statement of Stockholder’s Equity for the years ended December 31, 2013, 2012 and 2011, and (v) the Combined Notes to the Financial Statements for the year ended December 31, 2013. These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

**Filed herewith.

Genco hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that Genco has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

73